the realized prices that we receive for our production differ from nymex futures and spot market prices , principally due to : basis differentials which are dependent on actual delivery location ; adjustments for btu content ; quality of the hydrocarbons ; and gathering , processing and transportation costs . the following table sets forth our average differentials for the years ended december 31 , 2017 , 2018 and 2019 : replace_table_token_14_th _ ( 1 ) average realized prices are before the impact of hedging activities . the company 's derivative contracts as of december 31 , 2019 and december 31 , 2018 consisted of nymex-based fixed price swaps and basis differential swaps . under fixed price swaps , we receive a fixed price for our production and pay a variable market price to the contract counter-party . 39 as of december 31 , 2019 , we had nymex-based fixed price commodity swap arrangements , on approximately 90 % of the oil production from our estimated net proved developed producing reserves ( as of december 31 , 2019 ) through december 31 , 2020 , and 97 % for 2021. subsequent to december 31 , 2019 , we have entered into additional fixed price commodity swaps . taking these additional contracts into consideration , we have entered into fixed price commodity swap arrangements on approximately 91 % of the oil production of our estimated net proved developed producing reserves ( as of december 31 , 2019 ) through december 31 , 2020 , 99 % for 2021 , 104 % for 2022 , 77 % for 2023 and 93 % for 2024. by removing a portion of price volatility on our future oil and gas production , we believe we will mitigate , but not eliminate , the potential effects of changing commodity prices on our cash flows from operations for those periods . however , when prevailing market prices are higher than our contract prices , we will not realize increased cash flows on the portion of the production that has been hedged . we have in the past and will in the future sustain losses on both open and settled derivative contracts if market prices are higher than our contract prices . conversely , when prevailing market prices are lower than our contract prices , we will sustain realized and unrealized gains on our commodity derivative contracts . in 2019 , we recorded a loss of $ 26.8 million , consisting of a loss of $ 6.0 million on closed contracts and a loss of $ 20.8 million related to open contracts . in 2018 , we recognized a gain of $ 8.1 million , consisting of a loss of $ 19.0 million on closed contracts and a gain of $ 27.1 million related to open contracts . we have not designated any of these derivative contracts as a hedge as permitted by applicable accounting rules if certain conditions are met . the following table sets forth our derivative contracts at december 31 , 2019 : replace_table_token_15_th at december 31 , 2019 , the aggregate fair market value of our commodity derivative contracts was a liability of approximately $ 7.4 million . production volumes . our proved reserves will decline as oil and gas is produced , unless we find , acquire or develop additional properties containing proved reserves or conduct successful exploration and development activities . based on the reserve information set forth in our reserve report as of december 31 , 2019 , our average annual estimated decline rate for our net proved developed producing reserves is 41 % ; 19 % ; 15 % ; 12 % and 11 % in 2020 , 2021 , 2022 , 2023 and 2024 , respectively , 8 % in the following five years , and approximately 8 % thereafter . these rates of decline are estimates and actual production declines could be materially higher . while we have had some success in finding , acquiring and developing additional reserves , we have not always been able to fully replace the production volumes lost from natural field declines and property sales . our ability to acquire or find additional reserves in the future will be dependent , in part , upon the amount of available funds for acquisition , exploration and development projects . the decline in oil prices that occurred in march 2020 , has resulted in the suspension of our 2020 drilling program as well as shutting in production for some period of time . both of these events will impact our production volumes going forward . in addition to our ability to successfully drill wells , we must also market our production which depends substantially on the availability , proximity and capacity of gathering systems , pipelines and processing facilities , which are also known as midstream facilities , owned and operated by third parties . if adequate midstream facilities and services are not available to us on a timely basis and at acceptable costs , our production and results of operations could be adversely affected . both of our principal areas of operation ( the bakken and permian basin ) have experienced substantial development in recent years , and this has made it more difficult for providers of midstream infrastructure and services to keep pace with the corresponding increases in field-wide production . the ultimate timing and availability of adequate infrastructure is not within our control and we could experience capacity constraints for extended periods of time that would negatively impact our ability to meet our production targets . weather , regulatory developments and other factors also affect the adequacy of midstream infrastructure . we had cash capital expenditures during 2019 of approximately $ 108.7 million . story_separator_special_tag new wells brought onto production contributed 574 mmcf to production for the year ended december 31 , 2018. ngl sales increased to 508 mbbls for the year ended december 31 , 2018 from 476 mbbls for the same period of 2017. the increase in ngl sales was primarily due to increased gas production from fields in west texas and north dakota that have a higher ngl content than our historical gas production . lease operating expenses ( “ loe ” ) . loe for the year ended december 31 , 2018 increased to $ 24.3 million from $ 15.2 million in 2017. the increase in loe was primarily due to higher cost of services and new wells brought onto production during 2018 as well as higher cost incurred shutting in wells for frac protect and repairing wells damaged by frac hits from offset wells . loe per boe for the year ended december 31 , 2018 was $ 6.79 compared to $ 5.63 for the same period of 2017. the increase in loe per boe was attributable to higher costs which were somewhat offset by higher sales volumes in 2018 as compared to 2017 . production and ad valorem taxes . production and ad valorem taxes for the year ended december 31 , 2018 increased to $ 12.0 million from $ 7.2 million in 2017. the increase was primarily due to higher realized prices and sales volumes in 2018 as compared to 2017. production and ad valorem taxes as a percentage of oil and gas revenue remained constant at 8 % in 2018 and 2017. general and administrative ( “ g & a ” ) expense . g & a expense , excluding stock-based compensation , decreased to $ 9.7 million for the year ended december 31 , 2018 from $ 13.0 million in 2017. the decrease in 2018 was primarily due to incentive bonuses accrued in 2017 as well as a discretionary bonus paid in 2017. g & a expense per boe was $ 2.70 for the year ended december 31 , 2018 compared to $ 4.83 for the same period of 2017. the decrease in per boe was the result of the decrease in g & a expenses as well as the increase in production in 2018 as compared to 2017. stock-based compensation . options granted to employees and directors are valued at the date of grant and expense is recognized over the options vesting period . in addition to options , restricted shares of common stock have been granted and are valued at the date of grant and expense is recognized over their vesting period . stock- based compensation decreased to $ 2.4 million for the year ended december 31 , 2018 compared to $ 3.2 million for the same period of 2017. the decrease was primarily due stock based compensation relating to stock options being fully amortized prior to 2018 . 49 depreciation , depletion , and amortization ( “ dd & a ” ) expenses . dd & a expense excluding accretion , increased to $ 42.8 million for the year ended december 31 , 2018 from $ 26.2 million in 2017. dd & a expense increased primarily due to higher future development costs included in the december 31 , 2018 reserve report , based on current development program , as well as higher production volumes in 2018 as compared to 2017. dd & a per boe for 2018 was $ 11.94 compared to $ 9.72 in 2017. the increase in dd & a expense per boe was primarily due to a higher full cost pool as well as higher future development costs in 2018 as compared to 2017 and higher capital cost in relation to reserve additions . interest expense . interest expense increased to $ 7.1 million in 2018 from $ 2.5 million for 2017. the increase was primarily due to higher debt levels in 2018 as compared to 2017 , as well as higher interest rates in 2018 as compared to 2017. in 2018 the interest rate on our credit facility averaged 5.4 % as compared to 4.1 % in 2017. income taxes . due to loss carry forwards , we did not recognize any income tax expense for the years ended december 31 , 2018 and 2017 . ( gain ) loss on derivative contracts . our derivative contracts consisted of fixed price swaps and basis differential swaps in 2018 and fixed price swaps and basis differential swaps and collar contracts in 2017. the net estimated value of our commodity derivative contracts was an asset of approximately $ 15.1 million as of december 31 , 2018. when our derivative contract prices are higher than prevailing market prices , we recognize gains and conversely , when our derivative contract prices are lower than prevailing market prices , we incur losses . for the year-ended december 31 , 2018 , we recognized a gain of $ 8.1 million , consisting of a loss of $ 19.0 million on closed contracts and a gain of $ 27.1 million on the mark to market valuation on open contracts . for the year ended december 31 , 2017 , we incurred a loss on our derivative contracts of approximately $ 1.8 million , consisting of a gain of $ 2.5 million on closed contracts and a loss of $ 4.3 million on the mark to market valuation of open contracts . ceiling limitation write-down . as of december 31 , 2018 and 2017 , the net capitalized cost of our oil and gas properties did not exceed the future net revenues from our estimated proved reserves . the year-end amounts were calculated in accordance with sec rules utilizing the twelve month first-day-of-the-month average oil and gas prices for the year ended 2018 which were $ 59.65 per bbl of oil and $ 1.76 per mcf for gas as adjusted to reflect the expected realized prices for our oil and gas reserves . the twelve month first-day-of-the-month

liquidity and capital resources general . the oil and gas industry is a highly capital intensive and cyclical business . our capital requirements are driven principally by our obligations to service debt and to fund the following : the development and exploration of existing properties , including drilling and completion costs of wells ; acquisition of interests in additional oil and gas properties ; and production and gathering facilities . the amount of capital expenditures we are able to make has a direct impact on our ability to increase cash flow from operations and , thereby , will directly affect our ability to service our debt obligations and to grow the business through the development of existing properties and the acquisition of new properties . in january 2019 , we announced that we had engaged petrie partners to assist us in identifying and assessing our options for our bakken properties . in october 2019 we announced that we had broadened the engagement of petrie partners to include a more thorough review of our business and strategic plans , competitive positioning and potential alternative transactions that might further enhance shareholder value . petrie 's expanded mandate to assess options for abraxas is a broad one , which might include sales of assets , merger or acquisition transactions , additional financing alternatives or other strategic transactions .


 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.
     ```liquidity and capital resources general . the oil and gas industry is a highly capital intensive and cyclical business . our capital requirements are driven principally by our obligations to service debt and to fund the following : the development and exploration of existing properties , including drilling and completion costs of wells ; acquisition of interests in additional oil and gas properties ; and production and gathering facilities . the amount of capital expenditures we are able to make has a direct impact on our ability to increase cash flow from operations and , thereby , will directly affect our ability to service our debt obligations and to grow the business through the development of existing properties and the acquisition of new properties . in january 2019 , we announced that we had engaged petrie partners to assist us in identifying and assessing our options for our bakken properties . in october 2019 we announced that we had broadened the engagement of petrie partners to include a more thorough review of our business and strategic plans , competitive positioning and potential alternative transactions that might further enhance shareholder value . petrie 's expanded mandate to assess options for abraxas is a broad one , which might include sales of assets , merger or acquisition transactions , additional financing alternatives or other strategic transactions .
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 Suspicious Activity Report : the realized prices that we receive for our production differ from nymex futures and spot market prices , principally due to : basis differentials which are dependent on actual delivery location ; adjustments for btu content ; quality of the hydrocarbons ; and gathering , processing and transportation costs . the following table sets forth our average differentials for the years ended december 31 , 2017 , 2018 and 2019 : replace_table_token_14_th _ ( 1 ) average realized prices are before the impact of hedging activities . the company 's derivative contracts as of december 31 , 2019 and december 31 , 2018 consisted of nymex-based fixed price swaps and basis differential swaps . under fixed price swaps , we receive a fixed price for our production and pay a variable market price to the contract counter-party . 39 as of december 31 , 2019 , we had nymex-based fixed price commodity swap arrangements , on approximately 90 % of the oil production from our estimated net proved developed producing reserves ( as of december 31 , 2019 ) through december 31 , 2020 , and 97 % for 2021. subsequent to december 31 , 2019 , we have entered into additional fixed price commodity swaps . taking these additional contracts into consideration , we have entered into fixed price commodity swap arrangements on approximately 91 % of the oil production of our estimated net proved developed producing reserves ( as of december 31 , 2019 ) through december 31 , 2020 , 99 % for 2021 , 104 % for 2022 , 77 % for 2023 and 93 % for 2024. by removing a portion of price volatility on our future oil and gas production , we believe we will mitigate , but not eliminate , the potential effects of changing commodity prices on our cash flows from operations for those periods . however , when prevailing market prices are higher than our contract prices , we will not realize increased cash flows on the portion of the production that has been hedged . we have in the past and will in the future sustain losses on both open and settled derivative contracts if market prices are higher than our contract prices . conversely , when prevailing market prices are lower than our contract prices , we will sustain realized and unrealized gains on our commodity derivative contracts . in 2019 , we recorded a loss of $ 26.8 million , consisting of a loss of $ 6.0 million on closed contracts and a loss of $ 20.8 million related to open contracts . in 2018 , we recognized a gain of $ 8.1 million , consisting of a loss of $ 19.0 million on closed contracts and a gain of $ 27.1 million related to open contracts . we have not designated any of these derivative contracts as a hedge as permitted by applicable accounting rules if certain conditions are met . the following table sets forth our derivative contracts at december 31 , 2019 : replace_table_token_15_th at december 31 , 2019 , the aggregate fair market value of our commodity derivative contracts was a liability of approximately $ 7.4 million . production volumes . our proved reserves will decline as oil and gas is produced , unless we find , acquire or develop additional properties containing proved reserves or conduct successful exploration and development activities . based on the reserve information set forth in our reserve report as of december 31 , 2019 , our average annual estimated decline rate for our net proved developed producing reserves is 41 % ; 19 % ; 15 % ; 12 % and 11 % in 2020 , 2021 , 2022 , 2023 and 2024 , respectively , 8 % in the following five years , and approximately 8 % thereafter . these rates of decline are estimates and actual production declines could be materially higher . while we have had some success in finding , acquiring and developing additional reserves , we have not always been able to fully replace the production volumes lost from natural field declines and property sales . our ability to acquire or find additional reserves in the future will be dependent , in part , upon the amount of available funds for acquisition , exploration and development projects . the decline in oil prices that occurred in march 2020 , has resulted in the suspension of our 2020 drilling program as well as shutting in production for some period of time . both of these events will impact our production volumes going forward . in addition to our ability to successfully drill wells , we must also market our production which depends substantially on the availability , proximity and capacity of gathering systems , pipelines and processing facilities , which are also known as midstream facilities , owned and operated by third parties . if adequate midstream facilities and services are not available to us on a timely basis and at acceptable costs , our production and results of operations could be adversely affected . both of our principal areas of operation ( the bakken and permian basin ) have experienced substantial development in recent years , and this has made it more difficult for providers of midstream infrastructure and services to keep pace with the corresponding increases in field-wide production . the ultimate timing and availability of adequate infrastructure is not within our control and we could experience capacity constraints for extended periods of time that would negatively impact our ability to meet our production targets . weather , regulatory developments and other factors also affect the adequacy of midstream infrastructure . we had cash capital expenditures during 2019 of approximately $ 108.7 million . story_separator_special_tag new wells brought onto production contributed 574 mmcf to production for the year ended december 31 , 2018. ngl sales increased to 508 mbbls for the year ended december 31 , 2018 from 476 mbbls for the same period of 2017. the increase in ngl sales was primarily due to increased gas production from fields in west texas and north dakota that have a higher ngl content than our historical gas production . lease operating expenses ( “ loe ” ) . loe for the year ended december 31 , 2018 increased to $ 24.3 million from $ 15.2 million in 2017. the increase in loe was primarily due to higher cost of services and new wells brought onto production during 2018 as well as higher cost incurred shutting in wells for frac protect and repairing wells damaged by frac hits from offset wells . loe per boe for the year ended december 31 , 2018 was $ 6.79 compared to $ 5.63 for the same period of 2017. the increase in loe per boe was attributable to higher costs which were somewhat offset by higher sales volumes in 2018 as compared to 2017 . production and ad valorem taxes . production and ad valorem taxes for the year ended december 31 , 2018 increased to $ 12.0 million from $ 7.2 million in 2017. the increase was primarily due to higher realized prices and sales volumes in 2018 as compared to 2017. production and ad valorem taxes as a percentage of oil and gas revenue remained constant at 8 % in 2018 and 2017. general and administrative ( “ g & a ” ) expense . g & a expense , excluding stock-based compensation , decreased to $ 9.7 million for the year ended december 31 , 2018 from $ 13.0 million in 2017. the decrease in 2018 was primarily due to incentive bonuses accrued in 2017 as well as a discretionary bonus paid in 2017. g & a expense per boe was $ 2.70 for the year ended december 31 , 2018 compared to $ 4.83 for the same period of 2017. the decrease in per boe was the result of the decrease in g & a expenses as well as the increase in production in 2018 as compared to 2017. stock-based compensation . options granted to employees and directors are valued at the date of grant and expense is recognized over the options vesting period . in addition to options , restricted shares of common stock have been granted and are valued at the date of grant and expense is recognized over their vesting period . stock- based compensation decreased to $ 2.4 million for the year ended december 31 , 2018 compared to $ 3.2 million for the same period of 2017. the decrease was primarily due stock based compensation relating to stock options being fully amortized prior to 2018 . 49 depreciation , depletion , and amortization ( “ dd & a ” ) expenses . dd & a expense excluding accretion , increased to $ 42.8 million for the year ended december 31 , 2018 from $ 26.2 million in 2017. dd & a expense increased primarily due to higher future development costs included in the december 31 , 2018 reserve report , based on current development program , as well as higher production volumes in 2018 as compared to 2017. dd & a per boe for 2018 was $ 11.94 compared to $ 9.72 in 2017. the increase in dd & a expense per boe was primarily due to a higher full cost pool as well as higher future development costs in 2018 as compared to 2017 and higher capital cost in relation to reserve additions . interest expense . interest expense increased to $ 7.1 million in 2018 from $ 2.5 million for 2017. the increase was primarily due to higher debt levels in 2018 as compared to 2017 , as well as higher interest rates in 2018 as compared to 2017. in 2018 the interest rate on our credit facility averaged 5.4 % as compared to 4.1 % in 2017. income taxes . due to loss carry forwards , we did not recognize any income tax expense for the years ended december 31 , 2018 and 2017 . ( gain ) loss on derivative contracts . our derivative contracts consisted of fixed price swaps and basis differential swaps in 2018 and fixed price swaps and basis differential swaps and collar contracts in 2017. the net estimated value of our commodity derivative contracts was an asset of approximately $ 15.1 million as of december 31 , 2018. when our derivative contract prices are higher than prevailing market prices , we recognize gains and conversely , when our derivative contract prices are lower than prevailing market prices , we incur losses . for the year-ended december 31 , 2018 , we recognized a gain of $ 8.1 million , consisting of a loss of $ 19.0 million on closed contracts and a gain of $ 27.1 million on the mark to market valuation on open contracts . for the year ended december 31 , 2017 , we incurred a loss on our derivative contracts of approximately $ 1.8 million , consisting of a gain of $ 2.5 million on closed contracts and a loss of $ 4.3 million on the mark to market valuation of open contracts . ceiling limitation write-down . as of december 31 , 2018 and 2017 , the net capitalized cost of our oil and gas properties did not exceed the future net revenues from our estimated proved reserves . the year-end amounts were calculated in accordance with sec rules utilizing the twelve month first-day-of-the-month average oil and gas prices for the year ended 2018 which were $ 59.65 per bbl of oil and $ 1.76 per mcf for gas as adjusted to reflect the expected realized prices for our oil and gas reserves . the twelve month first-day-of-the-month

