additionally , for a discussion relating to the minimum remaining terms of our leases , refer to “ acreage ” in item 2 of this annual report on form 10‑k . 48 2018 highlights and future considerations operational highlights northern rocky mountains – williston basin our properties in the williston basin of north dakota and montana target the bakken and three forks formations . net production from the williston basin averaged 111.5 mboe/d for the fourth quarter of 2018 , representing a 4 % increase from 106.9 mboe/d in the third quarter of 2018. production from this area in the fourth quarter was negatively impacted by extended downtime at a third-party gas processing facility and gas curtailments resulting from takeaway capacity issues . the gas plant was returned to service late in the fourth quarter , and the curtailments have been lifted during the first part of 2019. across our acreage in the williston basin , we have implemented customized , right-sized completion designs which utilize the optimum volume of proppant , fluids , and frac stages to increase well performance while reducing cost . we plan to continue to use right-sized completion designs on wells we drill in 2019 , while also utilizing state-of-the-art drilling rigs , high-torque mud motors and 3-d bit cutter technology to reduce time-on-location and total well cost . as of december 31 , 2018 , we had five rigs active in the williston basin . we drilled 36 wells and put 41 operated wells on production in this area during the fourth quarter of 2018. central rocky mountains – denver-julesburg basin our redtail field in the denver-julesburg basin ( “ dj basin ” ) in weld county , colorado targets the niobrara and codell/fort hays formations . net production from the redtail field averaged 17.8 mboe/d in the fourth quarter of 2018 , representing a 16 % decrease from 21.2 mboe/d in the third quarter of 2018. we have established production in the niobrara “ a ” , “ b ” and “ c ” zones and the codell/fort hays formations . during 2017 , we completed and brought on production a significant portion of our drilled uncompleted well inventory ( “ ducs ” ) from yearend 2016. in late 2017 , based on the comparative well performance results of the dj basin to the williston basin , our management decided to concentrate development activities during 2018 in the williston basin . we completed 22 ducs in our redtail field during the first half of 2018 and have since ceased additional development activity in this area until commodity prices further recover . our redtail gas plant processes the associated gas produced from our wells in this area , and has a current inlet capacity of 50 mmcf/d . as of december 31 , 2018 , the plant was processing 30 mmcf/d . financing highlights on january 26 , 2018 , we paid $ 1.0 billion to redeem all of the then outstanding $ 961 million aggregate principal amount of our 2019 senior notes , which payment consisted of the 102.976 % redemption price plus all accrued and unpaid interest on the notes . we financed the redemption with proceeds from the issuance of our 2026 senior notes and borrowings under our credit agreement . refer to the “ long-term debt ” footnote in the notes to the consolidated financial statements for more information on this financing transaction . 2019 exploration and development budget our 2019 exploration and development ( “ e & d ” ) budget is a range of $ 800 million to $ 840 million , which we expect to fund substantially with net cash provided by our operating activities and cash on hand . the forecasted midpoint of the 2019 e & d budget of $ 820 million represents a slight decrease from the $ 832 million incurred on e & d expenditures during 2018. this reduced spending is primarily attributable to our redtail field where we incurred $ 83 million in drilling and development costs during 2018 , but where we have not allocated any of our 2019 e & d budget due to well performance results in this area compared to the williston basin . offsetting this decreased spending at our redtail field is an increase of $ 62 million of planned drilling and development costs in the northern rocky mountains . to the extent net cash provided by operating activities is higher or lower than currently anticipated , we would generate more or less free cash flow than we currently anticipate , adjust our e & d budget , enter into agreements with industry partners , divest certain oil and gas property interests , adjust borrowings outstanding under our credit facility or access the capital markets as necessary . the midpoint of our 2019 e & d budget currently is allocated among our major development areas as indicated in the table below . of our existing potential projects , we believe these present the opportunity for the highest return and most efficient use of our capital . 49 2019 exploration and development budget development area ( in millions ) northern rocky mountains $ 662 non-operated properties 40 land 30 other ( 1 ) 88 total $ 820 ( 1 ) comprised of facilities and exploration costs . acquisition and divestiture highlights on july 31 , 2018 , we completed the acquisition of approximately 54,800 net acres in the williston basin , including interests in 117 producing oil and gas wells and undeveloped acreage located in richland county , montana and mckenzie county , north dakota for an aggregate purchase price of $ 130 million ( before closing adjustments ) . the producing properties had estimated proved reserves of 25.7 mmboe as of the acquisition date , 84 % of which were crude oil and ngls . story_separator_special_tag these decreases were partially offset by new wells drilled and completed in the williston basin and dj basin which added 6,040 mbbl and 1,750 mbbl , respectively , of oil production during 2017 as compared to 2016. the ngl volume increase between periods generally relates to new wells drilled and completed in the williston basin and dj basin over the twelve months ended december 31 , 2017 , as well as additional volumes processed as more wells were connected to gas processing plants in the williston basin in an effort to increase our overall gas capture rate in this area and reduce flared volumes . many of the new williston basin wells are in areas with higher gas-to-oil production ratios than previously drilled areas . these ngl volume increases were partially offset by normal field production decline across all our areas . new wells drilled and completed at our williston basin and dj basin properties resulted in 8,555 mmcf and 910 mmcf , respectively , of additional gas volumes during 2017 as compared to 2016. this gas volume increase was entirely offset by normal field production decline across all of our areas and the 2016 and 2017 property divestitures , which negatively impacted gas production in 2017 by 690 mmcf . these overall production-related decreases in net revenue were offset by increases in the average sales price realized for oil , ngls and natural gas in 2017 compared to 2016. our average price for oil ( before the effects of hedging ) , ngls and natural gas increased 29 % , 80 % and 27 % , respectively , between periods . our average sales price realized for oil was impacted by deficiency payments we were making under two physical delivery contracts at our redtail field due to our inability to meet the minimum volume commitments under these contracts . during 2017 and 2016 , our total average sales price realized for oil was $ 2.27 per bbl lower and $ 1.27 per bbl lower , respectively , as a result of these deficiency payments . lease operating expenses . our loe during 2017 were $ 279 million , a $ 34 million decrease compared to 2016. this decrease was primarily due to a decline in the costs of oilfield goods and services resulting from cost reduction measures we have implemented and the elimination of loe attributable to properties that we divested during 2016 and 2017 , as well as the general downturn in the oil and gas industry . our lease operating expenses on a boe basis also decreased when comparing 2017 to 2016. loe per boe amounted to $ 6.47 during 2017 , which represents a decrease of $ 0.12 per boe ( or 2 % ) from 2016. this decrease was mainly due to the overall decrease in loe discussed above , partially offset by lower overall production volumes between periods . gathering , transportation , compression and other . gtc during 2017 was $ 91 million , a $ 12 million increase over 2016. this increase was primarily due to higher production volumes between periods , as well as higher gas processing and oil gathering fees . this increase was partially offset by $ 12 million of gtc attributable to properties that we divested during 2016 and 2017. gtc on a boe basis also increased when comparing 2017 to 2016. gtc per boe amounted to $ 2.10 during 2017 , which represents an increase of $ 0.44 per boe ( or 27 % ) from 2016. this increase was mainly due to the overall increase in gtc discussed above . 54 production and ad valorem taxes . our production and ad valorem taxes increased $ 9 million in 2017 as compared to 2016. this increase was related to $ 15 million of higher production taxes between periods due to higher oil , ngl and natural gas sales . our production taxes , however , are generally calculated as a percentage of net sales revenue before the effects of hedging , and this percentage on a company-wide basis remained relatively consistent at 8.3 % and 8.5 % for 2017 and 2016 , respectively . ad valorem taxes decreased $ 6 million during 2017 as compared to 2016 primarily due to the sale of our interests in the robinson lake and belfield gas processing plants and the associated natural gas , crude oil and water gathering systems effective january 1 , 2017 and the sale of our interests in our enhanced oil recovery project in the north ward estes field and certain co 2 properties in the mcelmo dome field in july 2016. depreciation , depletion and amortization . our dd & a expense decreased $ 223 million in 2017 as compared to 2016. the components of our dd & a expense were as follows ( in thousands ) : replace_table_token_18_th dd & a decreased between periods primarily due to $ 222 million in lower depletion expense , consisting of a $ 127 million decrease related to a lower depletion rate between periods and a $ 95 million decrease due to lower overall production volumes during 2017. on a boe basis , our overall dd & a rate of $ 22.01 for 2017 was 11 % lower than the rate of $ 24.64 in 2016. the primary factors contributing to this lower dd & a rate were ( i ) an increase to proved and proved developed reserves during the twelve months ended december 31 , 2017 ( excluding the effect of divestitures ) mainly due to higher average oil and natural gas prices used to calculate our reserves , as well as upward performance revisions , extensions and discoveries in our williston basin area , and ( ii ) the impact of property divestitures . exploration and impairment costs . our exploration and impairment costs increased $ 815 million in 2017 as compared to 2016. the components of our exploration and impairment expense were as follows (

loss on extinguishment of debt . during 2017 , we redeemed all of the remaining $ 275 million aggregate principal amount of 2018 senior subordinated notes and recognized a $ 2 million loss on extinguishment of debt . during 2016 , we recognized a net loss on extinguishment of debt of $ 42 million . in march 2016 , we completed the exchange of $ 477 million aggregate principal amount of our senior notes and senior subordinated notes for the same aggregate principal amount of new convertible notes , and recognized a $ 91 million gain on extinguishment of debt . subsequently , during the second quarter of 2016 , the holders of the new convertible notes voluntarily converted all $ 477 million aggregate principal amount of the new convertible notes for approximately 10.5 million shares of our common stock , and we recognized a $ 188 million loss on extinguishment of debt upon conversion . in june and july 2016 , we completed the exchange of $ 1.1 billion aggregate principal amount of our senior notes , convertible senior notes and senior subordinated notes for the same aggregate principal amount of mandatory convertible notes , and recognized a $ 57 million gain on extinguishment of debt . subsequently in july 2016 , $ 333 million aggregate principal amount of the mandatory convertible notes were converted into approximately 8.3 million shares of our common stock , and we recognized a $ 3 million gain on extinguishment of debt upon conversion . in august 2016 , we induced the exchange of an additional $ 38 million aggregate principal amount of the mandatory convertible notes for approximately 1.2 million shares of our common stock , and we recognized a $ 4 million debt inducement expense . income tax benefit .


 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.
     ```loss on extinguishment of debt . during 2017 , we redeemed all of the remaining $ 275 million aggregate principal amount of 2018 senior subordinated notes and recognized a $ 2 million loss on extinguishment of debt . during 2016 , we recognized a net loss on extinguishment of debt of $ 42 million . in march 2016 , we completed the exchange of $ 477 million aggregate principal amount of our senior notes and senior subordinated notes for the same aggregate principal amount of new convertible notes , and recognized a $ 91 million gain on extinguishment of debt . subsequently , during the second quarter of 2016 , the holders of the new convertible notes voluntarily converted all $ 477 million aggregate principal amount of the new convertible notes for approximately 10.5 million shares of our common stock , and we recognized a $ 188 million loss on extinguishment of debt upon conversion . in june and july 2016 , we completed the exchange of $ 1.1 billion aggregate principal amount of our senior notes , convertible senior notes and senior subordinated notes for the same aggregate principal amount of mandatory convertible notes , and recognized a $ 57 million gain on extinguishment of debt . subsequently in july 2016 , $ 333 million aggregate principal amount of the mandatory convertible notes were converted into approximately 8.3 million shares of our common stock , and we recognized a $ 3 million gain on extinguishment of debt upon conversion . in august 2016 , we induced the exchange of an additional $ 38 million aggregate principal amount of the mandatory convertible notes for approximately 1.2 million shares of our common stock , and we recognized a $ 4 million debt inducement expense . income tax benefit .
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 Suspicious Activity Report : additionally , for a discussion relating to the minimum remaining terms of our leases , refer to “ acreage ” in item 2 of this annual report on form 10‑k . 48 2018 highlights and future considerations operational highlights northern rocky mountains – williston basin our properties in the williston basin of north dakota and montana target the bakken and three forks formations . net production from the williston basin averaged 111.5 mboe/d for the fourth quarter of 2018 , representing a 4 % increase from 106.9 mboe/d in the third quarter of 2018. production from this area in the fourth quarter was negatively impacted by extended downtime at a third-party gas processing facility and gas curtailments resulting from takeaway capacity issues . the gas plant was returned to service late in the fourth quarter , and the curtailments have been lifted during the first part of 2019. across our acreage in the williston basin , we have implemented customized , right-sized completion designs which utilize the optimum volume of proppant , fluids , and frac stages to increase well performance while reducing cost . we plan to continue to use right-sized completion designs on wells we drill in 2019 , while also utilizing state-of-the-art drilling rigs , high-torque mud motors and 3-d bit cutter technology to reduce time-on-location and total well cost . as of december 31 , 2018 , we had five rigs active in the williston basin . we drilled 36 wells and put 41 operated wells on production in this area during the fourth quarter of 2018. central rocky mountains – denver-julesburg basin our redtail field in the denver-julesburg basin ( “ dj basin ” ) in weld county , colorado targets the niobrara and codell/fort hays formations . net production from the redtail field averaged 17.8 mboe/d in the fourth quarter of 2018 , representing a 16 % decrease from 21.2 mboe/d in the third quarter of 2018. we have established production in the niobrara “ a ” , “ b ” and “ c ” zones and the codell/fort hays formations . during 2017 , we completed and brought on production a significant portion of our drilled uncompleted well inventory ( “ ducs ” ) from yearend 2016. in late 2017 , based on the comparative well performance results of the dj basin to the williston basin , our management decided to concentrate development activities during 2018 in the williston basin . we completed 22 ducs in our redtail field during the first half of 2018 and have since ceased additional development activity in this area until commodity prices further recover . our redtail gas plant processes the associated gas produced from our wells in this area , and has a current inlet capacity of 50 mmcf/d . as of december 31 , 2018 , the plant was processing 30 mmcf/d . financing highlights on january 26 , 2018 , we paid $ 1.0 billion to redeem all of the then outstanding $ 961 million aggregate principal amount of our 2019 senior notes , which payment consisted of the 102.976 % redemption price plus all accrued and unpaid interest on the notes . we financed the redemption with proceeds from the issuance of our 2026 senior notes and borrowings under our credit agreement . refer to the “ long-term debt ” footnote in the notes to the consolidated financial statements for more information on this financing transaction . 2019 exploration and development budget our 2019 exploration and development ( “ e & d ” ) budget is a range of $ 800 million to $ 840 million , which we expect to fund substantially with net cash provided by our operating activities and cash on hand . the forecasted midpoint of the 2019 e & d budget of $ 820 million represents a slight decrease from the $ 832 million incurred on e & d expenditures during 2018. this reduced spending is primarily attributable to our redtail field where we incurred $ 83 million in drilling and development costs during 2018 , but where we have not allocated any of our 2019 e & d budget due to well performance results in this area compared to the williston basin . offsetting this decreased spending at our redtail field is an increase of $ 62 million of planned drilling and development costs in the northern rocky mountains . to the extent net cash provided by operating activities is higher or lower than currently anticipated , we would generate more or less free cash flow than we currently anticipate , adjust our e & d budget , enter into agreements with industry partners , divest certain oil and gas property interests , adjust borrowings outstanding under our credit facility or access the capital markets as necessary . the midpoint of our 2019 e & d budget currently is allocated among our major development areas as indicated in the table below . of our existing potential projects , we believe these present the opportunity for the highest return and most efficient use of our capital . 49 2019 exploration and development budget development area ( in millions ) northern rocky mountains $ 662 non-operated properties 40 land 30 other ( 1 ) 88 total $ 820 ( 1 ) comprised of facilities and exploration costs . acquisition and divestiture highlights on july 31 , 2018 , we completed the acquisition of approximately 54,800 net acres in the williston basin , including interests in 117 producing oil and gas wells and undeveloped acreage located in richland county , montana and mckenzie county , north dakota for an aggregate purchase price of $ 130 million ( before closing adjustments ) . the producing properties had estimated proved reserves of 25.7 mmboe as of the acquisition date , 84 % of which were crude oil and ngls . story_separator_special_tag these decreases were partially offset by new wells drilled and completed in the williston basin and dj basin which added 6,040 mbbl and 1,750 mbbl , respectively , of oil production during 2017 as compared to 2016. the ngl volume increase between periods generally relates to new wells drilled and completed in the williston basin and dj basin over the twelve months ended december 31 , 2017 , as well as additional volumes processed as more wells were connected to gas processing plants in the williston basin in an effort to increase our overall gas capture rate in this area and reduce flared volumes . many of the new williston basin wells are in areas with higher gas-to-oil production ratios than previously drilled areas . these ngl volume increases were partially offset by normal field production decline across all our areas . new wells drilled and completed at our williston basin and dj basin properties resulted in 8,555 mmcf and 910 mmcf , respectively , of additional gas volumes during 2017 as compared to 2016. this gas volume increase was entirely offset by normal field production decline across all of our areas and the 2016 and 2017 property divestitures , which negatively impacted gas production in 2017 by 690 mmcf . these overall production-related decreases in net revenue were offset by increases in the average sales price realized for oil , ngls and natural gas in 2017 compared to 2016. our average price for oil ( before the effects of hedging ) , ngls and natural gas increased 29 % , 80 % and 27 % , respectively , between periods . our average sales price realized for oil was impacted by deficiency payments we were making under two physical delivery contracts at our redtail field due to our inability to meet the minimum volume commitments under these contracts . during 2017 and 2016 , our total average sales price realized for oil was $ 2.27 per bbl lower and $ 1.27 per bbl lower , respectively , as a result of these deficiency payments . lease operating expenses . our loe during 2017 were $ 279 million , a $ 34 million decrease compared to 2016. this decrease was primarily due to a decline in the costs of oilfield goods and services resulting from cost reduction measures we have implemented and the elimination of loe attributable to properties that we divested during 2016 and 2017 , as well as the general downturn in the oil and gas industry . our lease operating expenses on a boe basis also decreased when comparing 2017 to 2016. loe per boe amounted to $ 6.47 during 2017 , which represents a decrease of $ 0.12 per boe ( or 2 % ) from 2016. this decrease was mainly due to the overall decrease in loe discussed above , partially offset by lower overall production volumes between periods . gathering , transportation , compression and other . gtc during 2017 was $ 91 million , a $ 12 million increase over 2016. this increase was primarily due to higher production volumes between periods , as well as higher gas processing and oil gathering fees . this increase was partially offset by $ 12 million of gtc attributable to properties that we divested during 2016 and 2017. gtc on a boe basis also increased when comparing 2017 to 2016. gtc per boe amounted to $ 2.10 during 2017 , which represents an increase of $ 0.44 per boe ( or 27 % ) from 2016. this increase was mainly due to the overall increase in gtc discussed above . 54 production and ad valorem taxes . our production and ad valorem taxes increased $ 9 million in 2017 as compared to 2016. this increase was related to $ 15 million of higher production taxes between periods due to higher oil , ngl and natural gas sales . our production taxes , however , are generally calculated as a percentage of net sales revenue before the effects of hedging , and this percentage on a company-wide basis remained relatively consistent at 8.3 % and 8.5 % for 2017 and 2016 , respectively . ad valorem taxes decreased $ 6 million during 2017 as compared to 2016 primarily due to the sale of our interests in the robinson lake and belfield gas processing plants and the associated natural gas , crude oil and water gathering systems effective january 1 , 2017 and the sale of our interests in our enhanced oil recovery project in the north ward estes field and certain co 2 properties in the mcelmo dome field in july 2016. depreciation , depletion and amortization . our dd & a expense decreased $ 223 million in 2017 as compared to 2016. the components of our dd & a expense were as follows ( in thousands ) : replace_table_token_18_th dd & a decreased between periods primarily due to $ 222 million in lower depletion expense , consisting of a $ 127 million decrease related to a lower depletion rate between periods and a $ 95 million decrease due to lower overall production volumes during 2017. on a boe basis , our overall dd & a rate of $ 22.01 for 2017 was 11 % lower than the rate of $ 24.64 in 2016. the primary factors contributing to this lower dd & a rate were ( i ) an increase to proved and proved developed reserves during the twelve months ended december 31 , 2017 ( excluding the effect of divestitures ) mainly due to higher average oil and natural gas prices used to calculate our reserves , as well as upward performance revisions , extensions and discoveries in our williston basin area , and ( ii ) the impact of property divestitures . exploration and impairment costs . our exploration and impairment costs increased $ 815 million in 2017 as compared to 2016. the components of our exploration and impairment expense were as follows (

