the borrowing base under our credit facility is scheduled to be redetermined on april 1 , 2018. 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 , 2015 , 2016 and 2017 : replace_table_token_16_th _ ( 1 ) average realized prices are before the impact of hedging activities . the company 's derivative contracts as of december 31 , 2017 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 63 % of the oil production of our estimated net proved developed producing reserves ( as of december 31 , 2017 ) through december 31 , 2018 , and 70 % for 2019 . subsequent to december 31 , 2017 , 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 86 % of the oil production of our estimated net proved developed 45 producing reserves ( as of december 31 , 2017 ) through december 31 , 2018 , 89 % for 2019 and 89 % for 2020. 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 2015 , we incurred a net gain of $ 19.3 million , consisting of a gain of $ 9.5 million related to closed contracts and a gain of $ 9.8 million related to open 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 . 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 , 2017 : fixed price swaps : oil - wti contract periods daily volume ( bbl ) swap price ( per bbl ) fixed swaps 2018 ( january - december ) 3,149 $ 50.38 2019 ( january - december ) 2,200 $ 55.27 at december 31 , 2017 , the aggregate fair market value of our commodity derivative contracts was a liability of approximately $ 13.2 million . in january and february 2018 , we entered into additional derivative contracts as follows : replace_table_token_17_th 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 , 2017 , our average annual estimated decline rate for our net proved developed producing reserves is 38 % , 21 % , 13 % , 11 % and 10 % in 2019 , 2020 , 2021 , 2022 and 2023 , 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 . we had capital expenditures during 2017 of $ 135.1 million , including non-cash capital 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 a ranch located in pecos county , texas known as the coyanosa draw ranch and one-half of the mineral interests under the coyanosa draw ranch ) related to our exploration and development activities . we have a capital expenditure budget for 2018 of approximately $ 140.0 million . approximately $ 71.2 million of the 2018 budget is allocated to acquiring acreage and developing our permian and delaware basin assets and $ 33.8 million to developing our bakken/three forks play in north dakota . the remaining $ 35.0 million is allocated to acquisitions , facilities and general corporate purposes . story_separator_special_tag stock-based compensation for the year ended december 31 , 2016 decreased to $ 3.2 million from $ 3.9 million in 2015. the decrease was due to lower grant prices in 2016 as compared to 2015. depreciation , depletion , and amortization expenses . dd & a expense decreased to $ 24.4 million for the year ended december 31 , 2016 from $ 38.7 million in 2015. dd & a expense decreased primarily due to proved property impairments recognized in 2015 and the first three quarters of 2016 , as well as decreased future development costs included in the 2016 reserve reports . dd & a expense per boe for 2016 was $ 10.80 compared to $ 17.76 in 2015. the decrease in dd & a expense per boe was due to a lower depletable base as the result of impairments as well as lower future development cost in 2016 as compared to 2015. interest expense . interest expense increased to $ 4.3 million in 2016 from $ 3.9 million for 2015. the increase was primarily due to higher interest rates in 2016 as compared to 2015. income taxes . in 2015 , an income tax benefit was recognized as the result of an overpayment of state income taxes in 2014 that was refunded in 2015 , as well as a benefit of a capital loss carryback which resulted in a refund of prior year federal taxes of $ 0.2 million . due to losses incurred and loss carry forwards , we did not recognize any income tax expense for the years ended december 31 , 2016 and december 31 , 2015 . ( gain ) loss on derivative contracts . derivative gains or losses are determined by actual derivative settlements during the period and by periodic mark to market valuation of derivative contracts in place . we have elected not to apply hedge accounting to our derivative contracts as prescribed by accounting standards codification 815 , derivatives and hedging `` asc 815 `` ; therefore , fluctuations in the market value of the derivative contracts are recognized in earnings during the current period . our derivative contracts consisted of fixed price swaps , basis differential swaps and collar contracts in 2016 and fixed price swaps and three way collar contracts in 2015. the net estimated value of our commodity derivative contracts was a liability approximately $ 9.0 million as of december 31 , 2016. 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 , 2016 , we recognized a loss on our derivative contracts of approximately $ 18.0 million , consisting of a gain of $ 1.8 million on closed contracts and a loss of $ 19.8 million on the mark to market valuation of open contracts . for the year-ended december 31 , 2015 , we incurred a gain of $ 19.3 million , consisting of a gain of $ 9.5 million on closed contracts and a gain of $ 9.8 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 . during 2015 , proceeds from the monetization of derivative contracts were approximately $ 4.6 million . 50 ceiling limitation write-down . we record the carrying value of our oil and gas properties using the full cost method of accounting for oil and gas properties . under this method , we capitalize the cost to acquire , explore for and develop oil and gas properties . under the full cost accounting rules , the net capitalized cost of oil and gas properties less related deferred taxes , are limited by country , to the lower of the unamortized cost or the cost ceiling , defined as the sum of the present value of estimated unescalated future net revenues from proved reserves , discounted at 10 % , plus the cost of properties not being amortized , if any , plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized , if any , less related income taxes . if the net capitalized cost of oil and gas properties exceeds the ceiling limit , we are subject to a ceiling limitation write-down to the extent of such excess . a ceiling limitation write-down is a charge to earnings which does not impact cash flows from operating activities . however , such write-downs do impact the amount of our stockholders ' equity and reported earnings . as of december 31 , 2015 , the net capitalized cost of our oil and gas properties exceeded the present value of our estimated proved reserves , resulting in the recognition of an impairment of $ 128.6 million in 2015. similarly , during 2016 , we recognized impairments of $ 67.6 million . 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 2016 which were $ 42.74 per bbl for oil and $ 2.50 per mcf for gas as adjusted to reflect the expected realized prices for our oil and gas reserves . story_separator_special_tag style= `` font-family : inherit ; font-size:10pt ; `` > future capital resources . our principal sources of capital going forward , for 2018 and beyond , are cash flows from operations , borrowings under our credit facility , cash on hand , proceeds from the sale of properties , monetizing of derivative instruments and if an opportunity presents itself , the sale of debt or equity securities , although we may not be able to complete financing on terms acceptable to us , if at all . cash from operating activities is dependent upon commodity prices and production volumes . a decrease in commodity

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 . our principal sources of capital are cash flows from operations , borrowings under our credit facility , cash on hand , proceeds from the sale of properties , and if an opportunity presents itself , the sale of debt or equity securities , although we may not be able to complete any financings on terms acceptable to us , if at all . operating cash flow . our operating cash flow is sensitive to many variables , the most volatile of which is the prices of the oil , gas and ngl we produce and sell . our consolidated cash flow from operations increased in 2017 , primarily due to increased commodity prices during the year ended december 31 , 2017 as compared to 2016. we expect cash flows from operations to continue to be a primary source of liquidity in 2018. commodity prices . prices are determined primarily by prevailing market conditions . regional and worldwide economic activity , weather and other substantially variable factors influence market conditions for these products . these factors , which are difficult to predict , create volatility in prices and are beyond our control . we have entered into nymex-based fixed price commodity swap arrangements on approximately 63 % of the oil production of our estimated net proved developed producing reserves ( as of december 31 , 2017 ) through december 31 , 2018 and 70 % for 2019 .


 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 . our principal sources of capital are cash flows from operations , borrowings under our credit facility , cash on hand , proceeds from the sale of properties , and if an opportunity presents itself , the sale of debt or equity securities , although we may not be able to complete any financings on terms acceptable to us , if at all . operating cash flow . our operating cash flow is sensitive to many variables , the most volatile of which is the prices of the oil , gas and ngl we produce and sell . our consolidated cash flow from operations increased in 2017 , primarily due to increased commodity prices during the year ended december 31 , 2017 as compared to 2016. we expect cash flows from operations to continue to be a primary source of liquidity in 2018. commodity prices . prices are determined primarily by prevailing market conditions . regional and worldwide economic activity , weather and other substantially variable factors influence market conditions for these products . these factors , which are difficult to predict , create volatility in prices and are beyond our control . we have entered into nymex-based fixed price commodity swap arrangements on approximately 63 % of the oil production of our estimated net proved developed producing reserves ( as of december 31 , 2017 ) through december 31 , 2018 and 70 % for 2019 .
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 Suspicious Activity Report : the borrowing base under our credit facility is scheduled to be redetermined on april 1 , 2018. 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 , 2015 , 2016 and 2017 : replace_table_token_16_th _ ( 1 ) average realized prices are before the impact of hedging activities . the company 's derivative contracts as of december 31 , 2017 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 63 % of the oil production of our estimated net proved developed producing reserves ( as of december 31 , 2017 ) through december 31 , 2018 , and 70 % for 2019 . subsequent to december 31 , 2017 , 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 86 % of the oil production of our estimated net proved developed 45 producing reserves ( as of december 31 , 2017 ) through december 31 , 2018 , 89 % for 2019 and 89 % for 2020. 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 2015 , we incurred a net gain of $ 19.3 million , consisting of a gain of $ 9.5 million related to closed contracts and a gain of $ 9.8 million related to open 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 . 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 , 2017 : fixed price swaps : oil - wti contract periods daily volume ( bbl ) swap price ( per bbl ) fixed swaps 2018 ( january - december ) 3,149 $ 50.38 2019 ( january - december ) 2,200 $ 55.27 at december 31 , 2017 , the aggregate fair market value of our commodity derivative contracts was a liability of approximately $ 13.2 million . in january and february 2018 , we entered into additional derivative contracts as follows : replace_table_token_17_th 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 , 2017 , our average annual estimated decline rate for our net proved developed producing reserves is 38 % , 21 % , 13 % , 11 % and 10 % in 2019 , 2020 , 2021 , 2022 and 2023 , 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 . we had capital expenditures during 2017 of $ 135.1 million , including non-cash capital 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 a ranch located in pecos county , texas known as the coyanosa draw ranch and one-half of the mineral interests under the coyanosa draw ranch ) related to our exploration and development activities . we have a capital expenditure budget for 2018 of approximately $ 140.0 million . approximately $ 71.2 million of the 2018 budget is allocated to acquiring acreage and developing our permian and delaware basin assets and $ 33.8 million to developing our bakken/three forks play in north dakota . the remaining $ 35.0 million is allocated to acquisitions , facilities and general corporate purposes . story_separator_special_tag stock-based compensation for the year ended december 31 , 2016 decreased to $ 3.2 million from $ 3.9 million in 2015. the decrease was due to lower grant prices in 2016 as compared to 2015. depreciation , depletion , and amortization expenses . dd & a expense decreased to $ 24.4 million for the year ended december 31 , 2016 from $ 38.7 million in 2015. dd & a expense decreased primarily due to proved property impairments recognized in 2015 and the first three quarters of 2016 , as well as decreased future development costs included in the 2016 reserve reports . dd & a expense per boe for 2016 was $ 10.80 compared to $ 17.76 in 2015. the decrease in dd & a expense per boe was due to a lower depletable base as the result of impairments as well as lower future development cost in 2016 as compared to 2015. interest expense . interest expense increased to $ 4.3 million in 2016 from $ 3.9 million for 2015. the increase was primarily due to higher interest rates in 2016 as compared to 2015. income taxes . in 2015 , an income tax benefit was recognized as the result of an overpayment of state income taxes in 2014 that was refunded in 2015 , as well as a benefit of a capital loss carryback which resulted in a refund of prior year federal taxes of $ 0.2 million . due to losses incurred and loss carry forwards , we did not recognize any income tax expense for the years ended december 31 , 2016 and december 31 , 2015 . ( gain ) loss on derivative contracts . derivative gains or losses are determined by actual derivative settlements during the period and by periodic mark to market valuation of derivative contracts in place . we have elected not to apply hedge accounting to our derivative contracts as prescribed by accounting standards codification 815 , derivatives and hedging `` asc 815 `` ; therefore , fluctuations in the market value of the derivative contracts are recognized in earnings during the current period . our derivative contracts consisted of fixed price swaps , basis differential swaps and collar contracts in 2016 and fixed price swaps and three way collar contracts in 2015. the net estimated value of our commodity derivative contracts was a liability approximately $ 9.0 million as of december 31 , 2016. 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 , 2016 , we recognized a loss on our derivative contracts of approximately $ 18.0 million , consisting of a gain of $ 1.8 million on closed contracts and a loss of $ 19.8 million on the mark to market valuation of open contracts . for the year-ended december 31 , 2015 , we incurred a gain of $ 19.3 million , consisting of a gain of $ 9.5 million on closed contracts and a gain of $ 9.8 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 . during 2015 , proceeds from the monetization of derivative contracts were approximately $ 4.6 million . 50 ceiling limitation write-down . we record the carrying value of our oil and gas properties using the full cost method of accounting for oil and gas properties . under this method , we capitalize the cost to acquire , explore for and develop oil and gas properties . under the full cost accounting rules , the net capitalized cost of oil and gas properties less related deferred taxes , are limited by country , to the lower of the unamortized cost or the cost ceiling , defined as the sum of the present value of estimated unescalated future net revenues from proved reserves , discounted at 10 % , plus the cost of properties not being amortized , if any , plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized , if any , less related income taxes . if the net capitalized cost of oil and gas properties exceeds the ceiling limit , we are subject to a ceiling limitation write-down to the extent of such excess . a ceiling limitation write-down is a charge to earnings which does not impact cash flows from operating activities . however , such write-downs do impact the amount of our stockholders ' equity and reported earnings . as of december 31 , 2015 , the net capitalized cost of our oil and gas properties exceeded the present value of our estimated proved reserves , resulting in the recognition of an impairment of $ 128.6 million in 2015. similarly , during 2016 , we recognized impairments of $ 67.6 million . 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 2016 which were $ 42.74 per bbl for oil and $ 2.50 per mcf for gas as adjusted to reflect the expected realized prices for our oil and gas reserves . story_separator_special_tag style= `` font-family : inherit ; font-size:10pt ; `` > future capital resources . our principal sources of capital going forward , for 2018 and beyond , are cash flows from operations , borrowings under our credit facility , cash on hand , proceeds from the sale of properties , monetizing of derivative instruments and if an opportunity presents itself , the sale of debt or equity securities , although we may not be able to complete financing on terms acceptable to us , if at all . cash from operating activities is dependent upon commodity prices and production volumes . a decrease in commodity

