due to the geographic concentration of our oil and natural gas properties in the williston basin , we believe the primary sources of opportunities , challenges and risks related to our business for both the short and long-term are : commodity prices for oil and natural gas ; transportation capacity ; availability and cost of services ; and availability of qualified personnel . our revenue , profitability and future growth rate depend substantially on factors beyond our control , such as economic , political and regulatory developments as well as competition from other sources of energy . prices for oil and natural gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil and natural gas , as well as market uncertainty , economic conditions and a variety of additional factors . since the inception of our oil and natural gas activities , commodity prices have experienced significant fluctuations and may fluctuate widely in the future . as a result of current oil prices , we have increased our planned 2017 capital expenditures as compared to 2016 , excluding acquisitions , and we are continuing to concentrate our drilling activities in certain areas that are the most economic in the williston basin . extended periods of low prices for oil or natural gas could materially and adversely affect our financial position , our results of operations , the quantities of oil and natural gas reserves that we can economically produce and our access to capital . in an effort to improve price realizations from the sale of our oil and natural gas , we manage our commodities marketing activities in-house , which enables us to market and sell our oil and natural gas to a broader array of potential purchasers . we enter into crude oil sales contracts with purchasers who have access to crude oil transportation capacity , utilize derivative financial 52 instruments to manage our commodity price risk and enter into physical delivery contracts to manage our price differentials . due to the availability of other markets and pipeline connections , we do not believe that the loss of any single oil or natural gas customer would have a material adverse effect on our results of operations or cash flows . additionally , we sell a significant amount of our crude oil production through gathering systems connected to multiple pipeline and rail facilities . these gathering systems , which originate at the wellhead , reduce the need to transport barrels by truck from the wellhead . currently , we are flowing approximately 90 % of our gross operated oil production through these gathering systems . please see “ item 1. business—marketing , transportation and major customers . ” our quarterly average net realized oil prices and average price differentials are shown in the tables below . replace_table_token_13_th replace_table_token_14_th replace_table_token_15_th ( 1 ) realized oil prices do not include the effect of derivative contract settlements . ( 2 ) price differential reflects the difference between realized oil prices and wti crude oil index prices . our market optionality on the crude oil gathering systems allows us to shift volumes between pipeline and rail markets in order to optimize price realizations . crude oil produced and sold in the williston basin has historically sold at a discount to wti due to transportation costs and takeaway capacity . in the past , there have been periods when this discount has substantially increased due to oil production in the area increasing to a point that it temporarily surpassed the available pipeline transportation , rail transportation and refining capacity in the area . expansions of both rail and pipeline facilities have reduced the prior constraint on oil transportation out of the williston basin and improved our price differentials received at the lease . in the first quarter of 2014 , our average price differentials relative to wti increased due to the pipeline market weakening as a result of refinery down time and increased u.s. and canadian production . in the second and third quarters of 2014 , stronger pipeline prices shifted more of our barrels towards the pipelines , but rail buyers had to compete with pipeline prices despite weaker brent differentials , resulting in price differentials relative to wti of approximately 9 % to 11 % . in the fourth quarter of 2014 , as wti crude oil prices declined , our price differentials increased as a percentage of wti but remained relatively flat in terms of the dollar per barrel discount to wti in the range of $ 9.00 to $ 10.50 per barrel of oil . in 2015 , our price differentials relative to wti strengthened as new pipelines opened to eastern canada and u.s. markets and transportation on rail gradually declined . in the first quarter of 2015 , as wti further declined , our price differentials continued to increase as a percentage of wti but decreased in terms of the dollar per barrel discount to wti to an average of $ 7.85 per barrel of oil . in the second quarter of 2015 , as wti improved , our price differentials returned to approximately 10 % as a percentage of wti and continued to decrease in terms of the dollar per barrel discount to wti to an average of $ 5.90 per barrel of oil . since the third quarter of 2015 , our price differentials have averaged less than $ 5.00 per barrel discount to wti . we expect differentials to improve as takeaway capacity in the williston basin will increase by over 500,000 barrels of oil per day if the dakota access pipeline is completed and put in service . we believe our large concentrated acreage position provides us with a multi-year inventory of drilling projects and requires forward planning visibility for obtaining services and necessary permits to drill wells . story_separator_special_tag well services operating expenses represent third-party working interest owners ' share of completion service costs , cost of goods sold and operating expenses incurred by ows . the $ 4.8 million decrease for the year ended december 31 , 2016 as compared to the year ended december 31 , 2015 was primarily attributable to the lower well completion activity , partially offset by ows completing opna wells with a higher average third-party working interest in the year ended december 31 , 2016 as compared to december 31 , 2015 . marketing , transportation and gathering expenses . marketing , transportation and gathering expenses increased $ 8.8 million year over year , or a $ 0.47 increase per boe , which was primarily attributable to a $ 10.3 million increase in costs related to bulk purchases coupled with a $ 0.4 million increase in natural gas gathering and processing expenses related to additional well connections on oms infrastructure and the start up of our natural gas processing plant in the third quarter of 2016 , offset by a decrease year over year of $ 1.2 million in the write down of our crude oil inventory to the lower of cost or market value at year-end and a $ 0.8 million decrease in oil transportation costs , primarily driven by lower trucking costs . excluding non-cash valuation adjustments and bulk purchases , our marketing , transportation and gathering expenses on a per boe basis remained relatively consistent at $ 1.60 and $ 1.62 for the years ended december 31 , 2016 and 2015 , respectively . production taxes . our production taxes for the years ended december 31 , 2016 and 2015 were 9.0 % and 9.6 % , respectively , as a percentage of oil and natural gas sales . the production tax rate decreased year over year primarily due to reduced extraction tax rates in north dakota beginning in january 2016. for the years ended december 31 , 2016 and 2015 , the percentage of our total production located in north dakota was approximately 92 % and 88 % , respectively . in 2015 , north dakota had a crude oil tax structure based on a 5 % production tax and a 6.5 % oil extraction tax , resulting in a combined tax rate of 11.5 % of crude oil revenues . in 2016 , the north dakota oil extraction tax was reduced to 5 % , resulting in a combined tax rate of 10 % of crude oil revenues . depreciation , depletion and amortization ( “ dd & a ” ) . dd & a expense decreased $ 9.0 million to $ 476.3 million for the year ended december 31 , 2016 as compared to the year ended december 31 , 2015 . the decrease in dd & a expense for the year ended december 31 , 2016 was primarily due to a decrease in the average dd & a rate to $ 25.84 per boe for the year ended december 31 , 2016 as compared to $ 26.34 per boe for the year ended december 31 , 2015 . the decrease in the dd & a rate was primarily due to lower well costs and higher recoverable reserves . rig termination . we did not early terminate any drilling rig contracts during the year ended december 31 , 2016. as a result of our lowered 2015 capital expenditure program , we elected to early terminate certain drilling rig contracts and recorded a rig termination expense of $ 3.9 million for the year ended december 31 , 2015 . impairment . during the years ended december 31 , 2016 and 2015 , we recorded total impairment charges of $ 4.7 million and $ 46.1 million , respectively . to adjust the carrying value of our properties held for sale to their estimated fair value , determined based on the expected sales price less costs to sell , we recorded impairment charges of $ 3.6 million and $ 9.4 million for the years ended december 31 , 2016 and 2015 , respectively . no other impairment charges of proved oil and gas or other properties were recorded in 2016 or 2015 . we also recorded non-cash impairment charges of $ 0.2 million and $ 14.4 million during the years ended december 31 , 2016 and 2015 , respectively , for unproved properties due to leases that expired during the period . as a result of periodic assessments of unproved properties not held-by-production , we recorded additional impairment charges of $ 0.9 million and $ 22.2 million related to acreage expiring in future periods because there were no plans to drill or extend the leases prior to their expiration . during the year ended december 31 , 2015 , these impairment charges included $ 15.2 million related to leases that expired during the year ended december 31 , 2016 . consequently , lower impairment charges for unproved properties were recorded during the year ended december 31 , 2016 as most leases that expired during the period had been previously impaired . in determining the amount of non-cash impairment charges for such periods , we considered the application of the factors described under “ critical accounting policies and estimates—impairment of proved properties ” and “ critical accounting policies and estimates—impairment of unproved properties . ” general and administrative ( “ g & a ” ) expenses . our g & a expenses increased $ 0.5 million for the year ended december 31 , 2016 from $ 92.5 million for the year ended december 31 , 2015 . ows g & a increased by $ 3.6 million primarily due to ows completing opna wells with a higher average third-party working interest during the year ended december 31 , 2016 as compared to the year ended december 31 , 2015 . excluding our intercompany elimination , gross ows g & a decreased $ 11.9 million . e & p g & a was

cash flows provided by financing activities net cash provided by financing activities was $ 844.3 million , $ 83.3 million and $ 158.8 million for the years ended december 31 , 2016 , 2015 and 2014 , respectively . for the year ended december 31 , 2016 , cash sourced through financing activities was provided by net proceeds from the issuance of our common stock , the issuance of our senior convertible notes , and the borrowings under our revolving credit facility , partially offset by the repurchase of a portion of our senior notes . for the year ended december 31 , 2015 , cash sourced through financing activities was provided by net proceeds from the issuance of our common stock , partially offset by net repayments on our revolving credit facility . for the year ended december 31 , 2014 , cash sourced through financing activities was provided by borrowings under our revolving credit facility . sale of common stock . on february 2 , 2016 , we completed a public offering of 39,100,000 shares of our common stock ( including 5,100,000 shares issued pursuant to the underwriters ' option to purchase additional common stock ) at a purchase price of $ 4.685 per share . we used the net proceeds from the offering of $ 182.8 million , after deducting underwriting discounts and commissions and offering expenses , for general corporate purposes .


 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 provided by financing activities net cash provided by financing activities was $ 844.3 million , $ 83.3 million and $ 158.8 million for the years ended december 31 , 2016 , 2015 and 2014 , respectively . for the year ended december 31 , 2016 , cash sourced through financing activities was provided by net proceeds from the issuance of our common stock , the issuance of our senior convertible notes , and the borrowings under our revolving credit facility , partially offset by the repurchase of a portion of our senior notes . for the year ended december 31 , 2015 , cash sourced through financing activities was provided by net proceeds from the issuance of our common stock , partially offset by net repayments on our revolving credit facility . for the year ended december 31 , 2014 , cash sourced through financing activities was provided by borrowings under our revolving credit facility . sale of common stock . on february 2 , 2016 , we completed a public offering of 39,100,000 shares of our common stock ( including 5,100,000 shares issued pursuant to the underwriters ' option to purchase additional common stock ) at a purchase price of $ 4.685 per share . we used the net proceeds from the offering of $ 182.8 million , after deducting underwriting discounts and commissions and offering expenses , for general corporate purposes .
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 Suspicious Activity Report : due to the geographic concentration of our oil and natural gas properties in the williston basin , we believe the primary sources of opportunities , challenges and risks related to our business for both the short and long-term are : commodity prices for oil and natural gas ; transportation capacity ; availability and cost of services ; and availability of qualified personnel . our revenue , profitability and future growth rate depend substantially on factors beyond our control , such as economic , political and regulatory developments as well as competition from other sources of energy . prices for oil and natural gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil and natural gas , as well as market uncertainty , economic conditions and a variety of additional factors . since the inception of our oil and natural gas activities , commodity prices have experienced significant fluctuations and may fluctuate widely in the future . as a result of current oil prices , we have increased our planned 2017 capital expenditures as compared to 2016 , excluding acquisitions , and we are continuing to concentrate our drilling activities in certain areas that are the most economic in the williston basin . extended periods of low prices for oil or natural gas could materially and adversely affect our financial position , our results of operations , the quantities of oil and natural gas reserves that we can economically produce and our access to capital . in an effort to improve price realizations from the sale of our oil and natural gas , we manage our commodities marketing activities in-house , which enables us to market and sell our oil and natural gas to a broader array of potential purchasers . we enter into crude oil sales contracts with purchasers who have access to crude oil transportation capacity , utilize derivative financial 52 instruments to manage our commodity price risk and enter into physical delivery contracts to manage our price differentials . due to the availability of other markets and pipeline connections , we do not believe that the loss of any single oil or natural gas customer would have a material adverse effect on our results of operations or cash flows . additionally , we sell a significant amount of our crude oil production through gathering systems connected to multiple pipeline and rail facilities . these gathering systems , which originate at the wellhead , reduce the need to transport barrels by truck from the wellhead . currently , we are flowing approximately 90 % of our gross operated oil production through these gathering systems . please see “ item 1. business—marketing , transportation and major customers . ” our quarterly average net realized oil prices and average price differentials are shown in the tables below . replace_table_token_13_th replace_table_token_14_th replace_table_token_15_th ( 1 ) realized oil prices do not include the effect of derivative contract settlements . ( 2 ) price differential reflects the difference between realized oil prices and wti crude oil index prices . our market optionality on the crude oil gathering systems allows us to shift volumes between pipeline and rail markets in order to optimize price realizations . crude oil produced and sold in the williston basin has historically sold at a discount to wti due to transportation costs and takeaway capacity . in the past , there have been periods when this discount has substantially increased due to oil production in the area increasing to a point that it temporarily surpassed the available pipeline transportation , rail transportation and refining capacity in the area . expansions of both rail and pipeline facilities have reduced the prior constraint on oil transportation out of the williston basin and improved our price differentials received at the lease . in the first quarter of 2014 , our average price differentials relative to wti increased due to the pipeline market weakening as a result of refinery down time and increased u.s. and canadian production . in the second and third quarters of 2014 , stronger pipeline prices shifted more of our barrels towards the pipelines , but rail buyers had to compete with pipeline prices despite weaker brent differentials , resulting in price differentials relative to wti of approximately 9 % to 11 % . in the fourth quarter of 2014 , as wti crude oil prices declined , our price differentials increased as a percentage of wti but remained relatively flat in terms of the dollar per barrel discount to wti in the range of $ 9.00 to $ 10.50 per barrel of oil . in 2015 , our price differentials relative to wti strengthened as new pipelines opened to eastern canada and u.s. markets and transportation on rail gradually declined . in the first quarter of 2015 , as wti further declined , our price differentials continued to increase as a percentage of wti but decreased in terms of the dollar per barrel discount to wti to an average of $ 7.85 per barrel of oil . in the second quarter of 2015 , as wti improved , our price differentials returned to approximately 10 % as a percentage of wti and continued to decrease in terms of the dollar per barrel discount to wti to an average of $ 5.90 per barrel of oil . since the third quarter of 2015 , our price differentials have averaged less than $ 5.00 per barrel discount to wti . we expect differentials to improve as takeaway capacity in the williston basin will increase by over 500,000 barrels of oil per day if the dakota access pipeline is completed and put in service . we believe our large concentrated acreage position provides us with a multi-year inventory of drilling projects and requires forward planning visibility for obtaining services and necessary permits to drill wells . story_separator_special_tag well services operating expenses represent third-party working interest owners ' share of completion service costs , cost of goods sold and operating expenses incurred by ows . the $ 4.8 million decrease for the year ended december 31 , 2016 as compared to the year ended december 31 , 2015 was primarily attributable to the lower well completion activity , partially offset by ows completing opna wells with a higher average third-party working interest in the year ended december 31 , 2016 as compared to december 31 , 2015 . marketing , transportation and gathering expenses . marketing , transportation and gathering expenses increased $ 8.8 million year over year , or a $ 0.47 increase per boe , which was primarily attributable to a $ 10.3 million increase in costs related to bulk purchases coupled with a $ 0.4 million increase in natural gas gathering and processing expenses related to additional well connections on oms infrastructure and the start up of our natural gas processing plant in the third quarter of 2016 , offset by a decrease year over year of $ 1.2 million in the write down of our crude oil inventory to the lower of cost or market value at year-end and a $ 0.8 million decrease in oil transportation costs , primarily driven by lower trucking costs . excluding non-cash valuation adjustments and bulk purchases , our marketing , transportation and gathering expenses on a per boe basis remained relatively consistent at $ 1.60 and $ 1.62 for the years ended december 31 , 2016 and 2015 , respectively . production taxes . our production taxes for the years ended december 31 , 2016 and 2015 were 9.0 % and 9.6 % , respectively , as a percentage of oil and natural gas sales . the production tax rate decreased year over year primarily due to reduced extraction tax rates in north dakota beginning in january 2016. for the years ended december 31 , 2016 and 2015 , the percentage of our total production located in north dakota was approximately 92 % and 88 % , respectively . in 2015 , north dakota had a crude oil tax structure based on a 5 % production tax and a 6.5 % oil extraction tax , resulting in a combined tax rate of 11.5 % of crude oil revenues . in 2016 , the north dakota oil extraction tax was reduced to 5 % , resulting in a combined tax rate of 10 % of crude oil revenues . depreciation , depletion and amortization ( “ dd & a ” ) . dd & a expense decreased $ 9.0 million to $ 476.3 million for the year ended december 31 , 2016 as compared to the year ended december 31 , 2015 . the decrease in dd & a expense for the year ended december 31 , 2016 was primarily due to a decrease in the average dd & a rate to $ 25.84 per boe for the year ended december 31 , 2016 as compared to $ 26.34 per boe for the year ended december 31 , 2015 . the decrease in the dd & a rate was primarily due to lower well costs and higher recoverable reserves . rig termination . we did not early terminate any drilling rig contracts during the year ended december 31 , 2016. as a result of our lowered 2015 capital expenditure program , we elected to early terminate certain drilling rig contracts and recorded a rig termination expense of $ 3.9 million for the year ended december 31 , 2015 . impairment . during the years ended december 31 , 2016 and 2015 , we recorded total impairment charges of $ 4.7 million and $ 46.1 million , respectively . to adjust the carrying value of our properties held for sale to their estimated fair value , determined based on the expected sales price less costs to sell , we recorded impairment charges of $ 3.6 million and $ 9.4 million for the years ended december 31 , 2016 and 2015 , respectively . no other impairment charges of proved oil and gas or other properties were recorded in 2016 or 2015 . we also recorded non-cash impairment charges of $ 0.2 million and $ 14.4 million during the years ended december 31 , 2016 and 2015 , respectively , for unproved properties due to leases that expired during the period . as a result of periodic assessments of unproved properties not held-by-production , we recorded additional impairment charges of $ 0.9 million and $ 22.2 million related to acreage expiring in future periods because there were no plans to drill or extend the leases prior to their expiration . during the year ended december 31 , 2015 , these impairment charges included $ 15.2 million related to leases that expired during the year ended december 31 , 2016 . consequently , lower impairment charges for unproved properties were recorded during the year ended december 31 , 2016 as most leases that expired during the period had been previously impaired . in determining the amount of non-cash impairment charges for such periods , we considered the application of the factors described under “ critical accounting policies and estimates—impairment of proved properties ” and “ critical accounting policies and estimates—impairment of unproved properties . ” general and administrative ( “ g & a ” ) expenses . our g & a expenses increased $ 0.5 million for the year ended december 31 , 2016 from $ 92.5 million for the year ended december 31 , 2015 . ows g & a increased by $ 3.6 million primarily due to ows completing opna wells with a higher average third-party working interest during the year ended december 31 , 2016 as compared to the year ended december 31 , 2015 . excluding our intercompany elimination , gross ows g & a decreased $ 11.9 million . e & p g & a was

