such declines could also require us to write down the carrying value of our oil and gas assets which would also cause a reduction in net income . finally , low commodity prices will likely cause a reduction of the borrowing base under our credit facility . the borrowing base under our credit facility is scheduled to be redetermined on march 28 , 2019. 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 , 2016 , 2017 and 2018 : 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 , 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 . our hedging arrangements equate to approximately 51 % of the oil production of our estimated net proved developed producing reserves ( as of december 31 , 2018 ) through december 31 , 2019 , 62 % for 2020 and 66 % for 2021. subsequent to december 31 , 2018 , in connection with the redetermination of our credit facility , 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 61 % of the oil production of our estimated net proved developed producing reserves ( as of december 31 , 2018 ) through december 31 , 2019 , 80 % for 2020 and 75 % for 2021. 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 2016 , we incurred a loss of $ 18.0 million , consisting of a gain of $ 1.8 million on closed contracts and a loss of $ 19.8 million related to open contracts . in 2017 , we incurred a loss of $ 1.8 million , consisting of a gain of $ 2.5 million on closed contracts and a loss of $ 4.3 million related to open contracts . in 2018 , we recorded 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 . 46 the following table sets forth our derivative contracts at december 31 , 2018 : replace_table_token_15_th at december 31 , 2018 , the aggregate fair market value of our commodity derivative contracts was an asset of approximately $ 15.1 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 , 2018 , our average annual estimated decline rate for our net proved developed producing reserves is 35 % ; 19 % ; 14 % ; 11 % and 9 % in 2019 , 2020 , 2021 , 2022 and 2023 , respectively , 11 % 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 . 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 capital expenditures during 2018 of approximately $ 174.0 story_separator_special_tag production and ad valorem taxes for the year ended december 31 , 2017 increased to $ 7.2 million from $ 5.5 million in 2016. the increase was primarily due to higher realized prices and sales volumes in 2017 as compared to 2016. production and ad valorem taxes as a percentage of oil and gas revenue decreased to 8 % in 2017 as compared to 10 % in 2016. the decrease in the percentage of oil and gas revenue was primarily due to increased production in texas which has lower production tax rates than the other states in which we operate . general and administrative ( “ g & a ” ) expense . g & a expense , excluding stock-based compensation , increased to $ 13.0 million for the year ended december 31 , 2017 from $ 10.4 million in 2016. the increase was primarily due to incentive bonuses accrued in 2017 as well as a one-time discretionary bonus paid in 2017. g & a expense per boe was $ 4.83 for the year ended december 31 , 2017 compared to $ 4.58 for the same period of 2016. 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 was consistent at $ 3.2 million for the years ended december 31 , 2017 and 2016. there were no significant grants of stock options or restricted stock in 2017 . 50 depreciation , depletion , and amortization ( “ dd & a ” ) expenses . dd & a expense , excluding accretion , increased to $ 26.2 million for the year ended december 31 , 2017 from $ 24.4 million in 2016. dd & a expense increased primarily due to higher future development costs included in the december 31 , 2017 reserve report as well as higher production volumes in 2017 as compared to 2016. dd & a per boe for 2017 was $ 9.72 compared to $ 10.80 in 2016. the decrease in dd & a expense per boe was primarily due to a higher reserve volumes in 2017 as compared to 2016. interest expense . interest expense decreased to $ 2.5 million in 2017 from $ 3.8 million for 2016. the decrease was primarily due to lower debt levels in 2017 as compared to 2016 , partially offset by higher interest rates in 2017 as compared to 2016. income taxes . due to losses incurred and loss carry forwards , we did not recognize any income tax expense for the years ended december 31 , 2017 and 2016 . ( gain ) loss on derivative contracts . our derivative contracts consisted of fixed price swaps , basis differential swaps and collar contracts in 2017 and 2016. the net estimated value of our commodity derivative contracts was a liability of approximately $ 13.2 million as of december 31 , 2017. when our derivative contract prices are higher than prevailing market prices , we incur gains and conversely , when our derivative contract prices are lower than prevailing market prices , we incur losses . 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 . for the year-ended december 31 , 2016 , we incurred a loss of $ 18.0 million , consisting of a gain of $ 1.8 million on closed contracts and a loss of $ 19.8 million related to open contracts . monetization of derivative contracts . during 2016 , we monetized certain of our derivative contracts . proceeds from the monetization were approximately $ 14.4 million . we did not monetize any derivative contracts in 2017. ceiling limitation write-down . during 2016 , we incurred impairments of $ 67.6 million . as of december 31 , 2017 , the net capitalized cost of our oil and gas properties did not exceed the present value of our estimated proved reserves . the year-end amount was calculated in accordance with sec rules utilizing the twelve month first-day-of-the-month average oil and gas prices for the year ended 2017 which were $ 46.83 per bbl for oil and $ 1.79 per mcf for gas as adjusted to reflect the expected realized prices for our oil and gas reserves . story_separator_special_tag id= `` 5588f2019171549568983040 `` > $ 23.1 million , current maturities of long-term debt of $ 0.3 million , the current amount of our derivative liability of $ 0.6 million and accrued expenses of $ 0.8 million . the working capital deficit is expected to be funded by cash flows from operations and borrowings under our credit facility . capital expenditures . capital expenditures in 2016 , 2017 and 2018 were $ 31.7 million , $ 135.1 million , and $ 174.0 million , respectively . expenditures in 2017 included non-cash expenditures of $ 26.8 million , ( which consisted of 2.0 million shares of our common stock issued in connection with an acquisition in august 2017 , all of our interest in the surface estate of coyanosa draw ranch and one-half of the mineral interests under the coyanosa draw ranch ) . the table below sets forth the components of these capital expenditures : replace_table_token_18_th during 2016 capital expenditures were primarily for exploration and for the development of our existing properties . during 2017 and 2018 , capital expenditures were for the exploration and development of our existing properties and acquisition of additional leasehold . expenditures in 2017 included non-cash expenditures of $ 26.8 million , ( which consisted of 2.0 million shares of our common stock issued in connection

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 addition in january 2019 , we announced that we had engaged petrie partners to assist us in identifying and assessing our options for our bakken properties . we are still early in this process and do not know the ultimate outcome . in the event that this process were to result in the sale of our bakken properties , we believe that the proceeds would be used to significantly pay down or fully retire our debt , support our raven no . 1 rig in the delaware basin until it achieves free cash flow and possibly buy back stock . we feel that the cash flow from these sources will be adequate to fund our operations into the future , long and short term .


 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 addition in january 2019 , we announced that we had engaged petrie partners to assist us in identifying and assessing our options for our bakken properties . we are still early in this process and do not know the ultimate outcome . in the event that this process were to result in the sale of our bakken properties , we believe that the proceeds would be used to significantly pay down or fully retire our debt , support our raven no . 1 rig in the delaware basin until it achieves free cash flow and possibly buy back stock . we feel that the cash flow from these sources will be adequate to fund our operations into the future , long and short term .
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 Suspicious Activity Report : such declines could also require us to write down the carrying value of our oil and gas assets which would also cause a reduction in net income . finally , low commodity prices will likely cause a reduction of the borrowing base under our credit facility . the borrowing base under our credit facility is scheduled to be redetermined on march 28 , 2019. 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 , 2016 , 2017 and 2018 : 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 , 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 . our hedging arrangements equate to approximately 51 % of the oil production of our estimated net proved developed producing reserves ( as of december 31 , 2018 ) through december 31 , 2019 , 62 % for 2020 and 66 % for 2021. subsequent to december 31 , 2018 , in connection with the redetermination of our credit facility , 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 61 % of the oil production of our estimated net proved developed producing reserves ( as of december 31 , 2018 ) through december 31 , 2019 , 80 % for 2020 and 75 % for 2021. 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 2016 , we incurred a loss of $ 18.0 million , consisting of a gain of $ 1.8 million on closed contracts and a loss of $ 19.8 million related to open contracts . in 2017 , we incurred a loss of $ 1.8 million , consisting of a gain of $ 2.5 million on closed contracts and a loss of $ 4.3 million related to open contracts . in 2018 , we recorded 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 . 46 the following table sets forth our derivative contracts at december 31 , 2018 : replace_table_token_15_th at december 31 , 2018 , the aggregate fair market value of our commodity derivative contracts was an asset of approximately $ 15.1 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 , 2018 , our average annual estimated decline rate for our net proved developed producing reserves is 35 % ; 19 % ; 14 % ; 11 % and 9 % in 2019 , 2020 , 2021 , 2022 and 2023 , respectively , 11 % 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 . 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 capital expenditures during 2018 of approximately $ 174.0 story_separator_special_tag production and ad valorem taxes for the year ended december 31 , 2017 increased to $ 7.2 million from $ 5.5 million in 2016. the increase was primarily due to higher realized prices and sales volumes in 2017 as compared to 2016. production and ad valorem taxes as a percentage of oil and gas revenue decreased to 8 % in 2017 as compared to 10 % in 2016. the decrease in the percentage of oil and gas revenue was primarily due to increased production in texas which has lower production tax rates than the other states in which we operate . general and administrative ( “ g & a ” ) expense . g & a expense , excluding stock-based compensation , increased to $ 13.0 million for the year ended december 31 , 2017 from $ 10.4 million in 2016. the increase was primarily due to incentive bonuses accrued in 2017 as well as a one-time discretionary bonus paid in 2017. g & a expense per boe was $ 4.83 for the year ended december 31 , 2017 compared to $ 4.58 for the same period of 2016. 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 was consistent at $ 3.2 million for the years ended december 31 , 2017 and 2016. there were no significant grants of stock options or restricted stock in 2017 . 50 depreciation , depletion , and amortization ( “ dd & a ” ) expenses . dd & a expense , excluding accretion , increased to $ 26.2 million for the year ended december 31 , 2017 from $ 24.4 million in 2016. dd & a expense increased primarily due to higher future development costs included in the december 31 , 2017 reserve report as well as higher production volumes in 2017 as compared to 2016. dd & a per boe for 2017 was $ 9.72 compared to $ 10.80 in 2016. the decrease in dd & a expense per boe was primarily due to a higher reserve volumes in 2017 as compared to 2016. interest expense . interest expense decreased to $ 2.5 million in 2017 from $ 3.8 million for 2016. the decrease was primarily due to lower debt levels in 2017 as compared to 2016 , partially offset by higher interest rates in 2017 as compared to 2016. income taxes . due to losses incurred and loss carry forwards , we did not recognize any income tax expense for the years ended december 31 , 2017 and 2016 . ( gain ) loss on derivative contracts . our derivative contracts consisted of fixed price swaps , basis differential swaps and collar contracts in 2017 and 2016. the net estimated value of our commodity derivative contracts was a liability of approximately $ 13.2 million as of december 31 , 2017. when our derivative contract prices are higher than prevailing market prices , we incur gains and conversely , when our derivative contract prices are lower than prevailing market prices , we incur losses . 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 . for the year-ended december 31 , 2016 , we incurred a loss of $ 18.0 million , consisting of a gain of $ 1.8 million on closed contracts and a loss of $ 19.8 million related to open contracts . monetization of derivative contracts . during 2016 , we monetized certain of our derivative contracts . proceeds from the monetization were approximately $ 14.4 million . we did not monetize any derivative contracts in 2017. ceiling limitation write-down . during 2016 , we incurred impairments of $ 67.6 million . as of december 31 , 2017 , the net capitalized cost of our oil and gas properties did not exceed the present value of our estimated proved reserves . the year-end amount was calculated in accordance with sec rules utilizing the twelve month first-day-of-the-month average oil and gas prices for the year ended 2017 which were $ 46.83 per bbl for oil and $ 1.79 per mcf for gas as adjusted to reflect the expected realized prices for our oil and gas reserves . story_separator_special_tag id= `` 5588f2019171549568983040 `` > $ 23.1 million , current maturities of long-term debt of $ 0.3 million , the current amount of our derivative liability of $ 0.6 million and accrued expenses of $ 0.8 million . the working capital deficit is expected to be funded by cash flows from operations and borrowings under our credit facility . capital expenditures . capital expenditures in 2016 , 2017 and 2018 were $ 31.7 million , $ 135.1 million , and $ 174.0 million , respectively . expenditures in 2017 included non-cash expenditures of $ 26.8 million , ( which consisted of 2.0 million shares of our common stock issued in connection with an acquisition in august 2017 , all of our interest in the surface estate of coyanosa draw ranch and one-half of the mineral interests under the coyanosa draw ranch ) . the table below sets forth the components of these capital expenditures : replace_table_token_18_th during 2016 capital expenditures were primarily for exploration and for the development of our existing properties . during 2017 and 2018 , capital expenditures were for the exploration and development of our existing properties and acquisition of additional leasehold . expenditures in 2017 included non-cash expenditures of $ 26.8 million , ( which consisted of 2.0 million shares of our common stock issued in connection

