the 2020 senior notes were used to finance a portion of the 2013 ef acquisition as well as adjust our total capitalization by retiring our high-cost $ 300 million of 10.375 % senior notes due 2016 , or 2016 senior notes resulting in an annual reduction of interest payments of $ 5.6 million . we also issued 10 million shares of common stock to the seller in connection with the 2013 ef acquisition . key developments the following general business developments and corporate actions had or will have a significant impact on the financial reporting and disclosure of our financial position , results of operations and cash flows : ( i ) drilling results and future development plans for the eagle ford shale , ( ii ) the 2013 ef acquisition , ( iii ) the amendment , or amendment , of the revolver , and the borrowing base redetermination thereunder , ( iv ) the sale of our natural gas gathering assets in south texas , ( v ) hedging a portion of our oil and gas production through calendar year 2015 to the levels permitted by our revolver and our internal policies , ( vi ) the tender offer and the redemption , or the tender offer and the redemption , of our 2016 senior notes and ( vii ) the private placement and subsequent registration of our 2020 senior notes to finance the 2013 ef acquisition , the tender offer and the redemption . drilling results and future development plans for the eagle ford shale during 2013 , we drilled 49 gross ( 30.8 net ) successful wells , and our joint venture partner drilled seven ( 2.8 net ) successful non-operated wells in the eagle ford shale . we also drilled one ( 0.5 net ) well that is currently under evaluation . our eagle ford shale production was approximately 11,169 net boepd during 2013 and 13,111 net boepd during the fourth quarter of 2013 with oil comprising approximately 78 percent , ngls approximately 12 percent and natural gas approximately 10 percent . in the eagle ford shale , we have a total of 179 gross ( 116.7 net ) producing wells , 13 gross ( 10.1 net ) operated wells completing or waiting on completion , two gross ( 0.9 net ) outside operated wells being completed , six gross ( 4.2 net ) operated wells being drilled and no outside operated wells being drilled as of february 19 , 2014. while our production during the fourth quarter was consistent with previous guidance , we had a number of wells brought on line later than anticipated and these wells did not contribute as much to the fourth quarter results as we had expected . in addition , our non-operated partner has suspended its drilling program . in response , we have increased our operated drilling rig count to six rigs where we intend to remain during 2014 , subject to market conditions . the average total drilling and completion cost per frac stage for our operated eagle ford shale wells was approximately $ 380,000 in the fourth quarter of 2013 , as compared to $ 390,000 in the third quarter of 2013. in addition to the sequential decrease in costs per frac stage , our well productivity per stage increased as a result of pumping additional proppant and the continued use of multi-well pads and “ zipper fracs . ” a total of 22 of our recently drilled wells were drilled off of ten multi-well pads , with an average effective nominal spacing of approximately 60 acres . we have approximately 118,000 gross ( 80,000 net ) acres as of february 19 , 2014 , which to a large extent are contiguous and the majority of which are in the “ volatile oil window ” of the eagle ford shale . approximately 96,800 gross ( 70,300 net ) acres are operated by us . 28 acquisition and integration of new eagle ford shale assets we closed the 2013 ef acquisition on april 24 , 2013 , or the acquisition date , and acquired approximately 40,600 gross ( 17,700 net ) mineral acres , including producing and undeveloped property , located in gonzales and lavaca counties , texas most of which was adjacent to our existing eagle ford shale position . the 2013 ef acquisition was originally valued at $ 401 million with an effective date of january 1 , 2013 , or the effective date . on the acquisition date , we paid approximately $ 380 million in cash , including approximately $ 19 million of initial purchase price adjustments related to the period from the effective date to the acquisition date utilizing a portion of the proceeds from the 2020 senior notes offering , and issued to the seller 10 million shares of our common stock , or shares , with a fair value of $ 4.23 per share . shortly after the acquisition date , certain of our joint interest partners exercised preferential rights related to the 2013 ef acquisition . we received approximately $ 21 million from the exercise of those rights , which was recorded as a decrease to the purchase price of the 2013 ef acquisition . in september 2013 , the seller divested all of the shares . see item 3 , “ legal proceedings ” for information regarding an arbitration in which we are involved with the seller . the 2013 ef acquisition included working interests in 46 gross ( 22.1 net ) producing wells . at the time of the 2013 ef acquisition , the estimated net oil and gas production for the acquired assets was approximately 2,700 boepd . based on the seller 's third-party reserve engineering firm ' s year-end 2012 review of the acquired assets , proved reserves were approximately 12.0 mmboe , 96 percent of which were oil and ngls and 37 percent of which were proved developed . story_separator_special_tag included in the price variance for natural gas was approximately $ 0.7 million of unfavorable adjustments attributable to the change in prices associated with gas imbalances due to us from partners in the mid-continent region . 37 the following table provides an analysis of the change in our revenues for 2012 as compared to 2011. replace_table_token_43_th effects of derivatives in 2012 and 2011 , we received $ 28.3 million and $ 23.6 million , respectively , in cash settlements of oil and gas derivatives . the following table reconciles crude oil and natural gas revenues to realized prices , as adjusted for derivative activities , for the periods presented : replace_table_token_44_th gain on sales of property and equipment in 2012 , we recognized a gain of $ 3.3 million attributable to the sale of substantially all of our appalachian natural gas assets for proceeds of $ 95.7 million , net of transaction costs . in 2011 , we sold approximately 2,700 net undeveloped acres in butler and armstrong counties in pennsylvania for proceeds of $ 8.1 million , net of transaction costs , and recognized a gain of $ 3.3 million . we also recognized a gain of $ 0.6 million in 2012 attributable to the sale of our remaining undeveloped acreage in those counties . in addition , we recognized several individually insignificant gains on the sale of property , equipment , tubular inventory and well material during both periods . production and lifting costs replace_table_token_45_th lease operating expense decreased on an absolute basis during 2012 due primarily to the effect of the sale of our higher-cost appalachian and arkoma basin natural gas properties . in addition to the effect of property sales , we incurred lower repair and maintenance expenses and lower compression costs during 2012. cost decreases were partially offset by higher environmental and regulatory compliance , chemical treatment , field contracting and well tending costs attributable to our significantly expanded oil drilling program . 38 replace_table_token_46_th gathering , processing and transportation charges decreased on an absolute basis during 2012 due primarily to the effect of the sale of our appalachian and arkoma basin natural gas properties , partially offset by higher processing costs related to increased natural gas production in the eagle ford shale as well as higher transportation costs in the appalachian region in 2012 for periods prior to the sale . production and ad valorem taxes replace_table_token_47_th production and ad valorem taxes decreased during 2012 due primarily to the recognition of oklahoma severance tax rebates of $ 2.8 million attributable to horizontal and ultra-deep wells for the period of july 1 , 2009 through june 30 , 2011. reductions were also recognized for production taxes on certain texas wells in 2012 and for a property tax recovery attributable to west virginia wells in 2011. production taxes also decreased due to the appalachian and arkoma basin natural gas properties sales as well as lower overall natural gas volumes and prices in 2012 as compared to 2011. general and administrative replace_table_token_48_th recurring general and administrative expenses decreased due to reduced headcount and lower support costs following the sale of our appalachian and arkoma basin natural gas properties . liability-classified share-based compensation is attributable to our pbrsus , which were issued for the first time in 2012. the 2012 grant of pbrsus are payable in cash in 2015 upon achievement of specified market-based performance metrics . equity-classified share-based compensation attributable to stock options and restricted stock units decreased during 2012 due primarily to a lower number of awards granted . restructuring expenses for both the 2012 and 2011 periods include employee termination benefits and office relocation costs . the 2012 charge includes a provision for lease costs associated with the closing of our canonsburg , pennsylvania office , partially offset by a favorable adjustment to the lease obligation for our former tulsa , oklahoma office due to a change in estimated sub-lease rental income . 39 exploration the following table sets forth the components of exploration expenses for the periods presented : replace_table_token_49_th unproved leasehold amortization declined during 2012 as costs related to successful eagle ford shale wells were transferred to proved properties . geological and geophysical costs decreased during 2012 because our efforts in 2012 were concentrated on development drilling in the eagle ford shale whereas in 2011 we conducted exploratory prospect activities in multiple areas . dry hole costs in 2011 related to several unsuccessful wells in the mid-continent region . we also recorded drilling rig standby charges in 2011 in connection with the suspension of our exploratory drilling program in the marcellus shale . depreciation , depletion and amortization the following tables set forth the nature of the dd & a variances for the periods presented : replace_table_token_50_th the effect of lower overall production volumes on dd & a was more than offset by higher depletion rates associated with oil and ngl production . our average dd & a rate increased due primarily to higher capitalized finding and development costs attributable to our drilling program in the eagle ford shale as well as lower natural gas reserves due to revisions . impairments the following table summarizes the impairments recorded for the periods presented : replace_table_token_51_th in 2012 , we recognized a $ 28.4 million impairment of our appalachian natural gas assets triggered by the expected disposition of those properties , and a $ 75.0 million impairment of our marcellus shale assets due primarily to market declines in natural gas prices and the resultant reduction in proved natural gas reserves . in 2012 , we also recognized an impairment of certain tubular inventory and well materials triggered primarily by declines in asset quality . in 2011 , we recognized an impairment of our arkoma basin natural gas assets for $ 71.1 million , which was triggered by the expected disposition of those properties . also during 2011 , we recognized impairments of our horizontal coal bed methane properties in the appalachian region for $ 26.6

cash flows from financing activities . in april 2013 , we issued the the 2020 senior notes which were used to fund the 2013 ef acquisition and a portion of the tender offer and the redemption of our outstanding 2016 senior notes . we incurred and paid costs associated with the issuance of the 2020 senior notes as well as costs associated with an amendment to our revolver . cash flows from financing activities for 2013 include net borrowings under the revolver while the 2012 period includes net repayments under the revolver which were funded by the proceeds from the sale of our appalachian natural gas assets and a federal income tax refund . dividends paid in the 2013 period were attributable to our 6 % series a convertible perpetual preferred stock , or the 6 % preferred stock , and dividends paid in 2012 were attributable to our common stock . capitalization the following table summarizes our total capitalization as of the dates presented : replace_table_token_60_th _ 1 the 2016 senior notes were retired in 2013 in connection with the tender offer and the redemption . 2 includes 11,500 shares of the 6 % preferred stock which has a liquidation preference of $ 10,000 per share , or $ 115 million . revolving credit facility . borrowings under the revolver bear interest , at our option , at either ( i ) a rate derived from libor , as adjusted for statutory reserve requirements for eurocurrency liabilities , or adjusted libor , plus an applicable margin ( ranging from 1.500 % to 2.500 % ) or ( ii ) the greater of ( a ) the prime rate , ( b ) the federal funds effective rate plus 0.5 % or ( c ) the one-month adjusted libor plus 1.0 % , and , in each case , plus an applicable margin ( ranging from 0.500 % to 1.500 % ) . in each case , the applicable margin is determined based on the ratio of our outstanding borrowings to the available revolver capacity .


 Write a concise suspicious activity report of the following text delimited by triple backquotes. Return your response as a formal report which covers the key points highlighting the location,dates,entity names and account holder information in chronological order of the text.
     ```cash flows from financing activities . in april 2013 , we issued the the 2020 senior notes which were used to fund the 2013 ef acquisition and a portion of the tender offer and the redemption of our outstanding 2016 senior notes . we incurred and paid costs associated with the issuance of the 2020 senior notes as well as costs associated with an amendment to our revolver . cash flows from financing activities for 2013 include net borrowings under the revolver while the 2012 period includes net repayments under the revolver which were funded by the proceeds from the sale of our appalachian natural gas assets and a federal income tax refund . dividends paid in the 2013 period were attributable to our 6 % series a convertible perpetual preferred stock , or the 6 % preferred stock , and dividends paid in 2012 were attributable to our common stock . capitalization the following table summarizes our total capitalization as of the dates presented : replace_table_token_60_th _ 1 the 2016 senior notes were retired in 2013 in connection with the tender offer and the redemption . 2 includes 11,500 shares of the 6 % preferred stock which has a liquidation preference of $ 10,000 per share , or $ 115 million . revolving credit facility . borrowings under the revolver bear interest , at our option , at either ( i ) a rate derived from libor , as adjusted for statutory reserve requirements for eurocurrency liabilities , or adjusted libor , plus an applicable margin ( ranging from 1.500 % to 2.500 % ) or ( ii ) the greater of ( a ) the prime rate , ( b ) the federal funds effective rate plus 0.5 % or ( c ) the one-month adjusted libor plus 1.0 % , and , in each case , plus an applicable margin ( ranging from 0.500 % to 1.500 % ) . in each case , the applicable margin is determined based on the ratio of our outstanding borrowings to the available revolver capacity .
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 Suspicious Activity Report : the 2020 senior notes were used to finance a portion of the 2013 ef acquisition as well as adjust our total capitalization by retiring our high-cost $ 300 million of 10.375 % senior notes due 2016 , or 2016 senior notes resulting in an annual reduction of interest payments of $ 5.6 million . we also issued 10 million shares of common stock to the seller in connection with the 2013 ef acquisition . key developments the following general business developments and corporate actions had or will have a significant impact on the financial reporting and disclosure of our financial position , results of operations and cash flows : ( i ) drilling results and future development plans for the eagle ford shale , ( ii ) the 2013 ef acquisition , ( iii ) the amendment , or amendment , of the revolver , and the borrowing base redetermination thereunder , ( iv ) the sale of our natural gas gathering assets in south texas , ( v ) hedging a portion of our oil and gas production through calendar year 2015 to the levels permitted by our revolver and our internal policies , ( vi ) the tender offer and the redemption , or the tender offer and the redemption , of our 2016 senior notes and ( vii ) the private placement and subsequent registration of our 2020 senior notes to finance the 2013 ef acquisition , the tender offer and the redemption . drilling results and future development plans for the eagle ford shale during 2013 , we drilled 49 gross ( 30.8 net ) successful wells , and our joint venture partner drilled seven ( 2.8 net ) successful non-operated wells in the eagle ford shale . we also drilled one ( 0.5 net ) well that is currently under evaluation . our eagle ford shale production was approximately 11,169 net boepd during 2013 and 13,111 net boepd during the fourth quarter of 2013 with oil comprising approximately 78 percent , ngls approximately 12 percent and natural gas approximately 10 percent . in the eagle ford shale , we have a total of 179 gross ( 116.7 net ) producing wells , 13 gross ( 10.1 net ) operated wells completing or waiting on completion , two gross ( 0.9 net ) outside operated wells being completed , six gross ( 4.2 net ) operated wells being drilled and no outside operated wells being drilled as of february 19 , 2014. while our production during the fourth quarter was consistent with previous guidance , we had a number of wells brought on line later than anticipated and these wells did not contribute as much to the fourth quarter results as we had expected . in addition , our non-operated partner has suspended its drilling program . in response , we have increased our operated drilling rig count to six rigs where we intend to remain during 2014 , subject to market conditions . the average total drilling and completion cost per frac stage for our operated eagle ford shale wells was approximately $ 380,000 in the fourth quarter of 2013 , as compared to $ 390,000 in the third quarter of 2013. in addition to the sequential decrease in costs per frac stage , our well productivity per stage increased as a result of pumping additional proppant and the continued use of multi-well pads and “ zipper fracs . ” a total of 22 of our recently drilled wells were drilled off of ten multi-well pads , with an average effective nominal spacing of approximately 60 acres . we have approximately 118,000 gross ( 80,000 net ) acres as of february 19 , 2014 , which to a large extent are contiguous and the majority of which are in the “ volatile oil window ” of the eagle ford shale . approximately 96,800 gross ( 70,300 net ) acres are operated by us . 28 acquisition and integration of new eagle ford shale assets we closed the 2013 ef acquisition on april 24 , 2013 , or the acquisition date , and acquired approximately 40,600 gross ( 17,700 net ) mineral acres , including producing and undeveloped property , located in gonzales and lavaca counties , texas most of which was adjacent to our existing eagle ford shale position . the 2013 ef acquisition was originally valued at $ 401 million with an effective date of january 1 , 2013 , or the effective date . on the acquisition date , we paid approximately $ 380 million in cash , including approximately $ 19 million of initial purchase price adjustments related to the period from the effective date to the acquisition date utilizing a portion of the proceeds from the 2020 senior notes offering , and issued to the seller 10 million shares of our common stock , or shares , with a fair value of $ 4.23 per share . shortly after the acquisition date , certain of our joint interest partners exercised preferential rights related to the 2013 ef acquisition . we received approximately $ 21 million from the exercise of those rights , which was recorded as a decrease to the purchase price of the 2013 ef acquisition . in september 2013 , the seller divested all of the shares . see item 3 , “ legal proceedings ” for information regarding an arbitration in which we are involved with the seller . the 2013 ef acquisition included working interests in 46 gross ( 22.1 net ) producing wells . at the time of the 2013 ef acquisition , the estimated net oil and gas production for the acquired assets was approximately 2,700 boepd . based on the seller 's third-party reserve engineering firm ' s year-end 2012 review of the acquired assets , proved reserves were approximately 12.0 mmboe , 96 percent of which were oil and ngls and 37 percent of which were proved developed . story_separator_special_tag included in the price variance for natural gas was approximately $ 0.7 million of unfavorable adjustments attributable to the change in prices associated with gas imbalances due to us from partners in the mid-continent region . 37 the following table provides an analysis of the change in our revenues for 2012 as compared to 2011. replace_table_token_43_th effects of derivatives in 2012 and 2011 , we received $ 28.3 million and $ 23.6 million , respectively , in cash settlements of oil and gas derivatives . the following table reconciles crude oil and natural gas revenues to realized prices , as adjusted for derivative activities , for the periods presented : replace_table_token_44_th gain on sales of property and equipment in 2012 , we recognized a gain of $ 3.3 million attributable to the sale of substantially all of our appalachian natural gas assets for proceeds of $ 95.7 million , net of transaction costs . in 2011 , we sold approximately 2,700 net undeveloped acres in butler and armstrong counties in pennsylvania for proceeds of $ 8.1 million , net of transaction costs , and recognized a gain of $ 3.3 million . we also recognized a gain of $ 0.6 million in 2012 attributable to the sale of our remaining undeveloped acreage in those counties . in addition , we recognized several individually insignificant gains on the sale of property , equipment , tubular inventory and well material during both periods . production and lifting costs replace_table_token_45_th lease operating expense decreased on an absolute basis during 2012 due primarily to the effect of the sale of our higher-cost appalachian and arkoma basin natural gas properties . in addition to the effect of property sales , we incurred lower repair and maintenance expenses and lower compression costs during 2012. cost decreases were partially offset by higher environmental and regulatory compliance , chemical treatment , field contracting and well tending costs attributable to our significantly expanded oil drilling program . 38 replace_table_token_46_th gathering , processing and transportation charges decreased on an absolute basis during 2012 due primarily to the effect of the sale of our appalachian and arkoma basin natural gas properties , partially offset by higher processing costs related to increased natural gas production in the eagle ford shale as well as higher transportation costs in the appalachian region in 2012 for periods prior to the sale . production and ad valorem taxes replace_table_token_47_th production and ad valorem taxes decreased during 2012 due primarily to the recognition of oklahoma severance tax rebates of $ 2.8 million attributable to horizontal and ultra-deep wells for the period of july 1 , 2009 through june 30 , 2011. reductions were also recognized for production taxes on certain texas wells in 2012 and for a property tax recovery attributable to west virginia wells in 2011. production taxes also decreased due to the appalachian and arkoma basin natural gas properties sales as well as lower overall natural gas volumes and prices in 2012 as compared to 2011. general and administrative replace_table_token_48_th recurring general and administrative expenses decreased due to reduced headcount and lower support costs following the sale of our appalachian and arkoma basin natural gas properties . liability-classified share-based compensation is attributable to our pbrsus , which were issued for the first time in 2012. the 2012 grant of pbrsus are payable in cash in 2015 upon achievement of specified market-based performance metrics . equity-classified share-based compensation attributable to stock options and restricted stock units decreased during 2012 due primarily to a lower number of awards granted . restructuring expenses for both the 2012 and 2011 periods include employee termination benefits and office relocation costs . the 2012 charge includes a provision for lease costs associated with the closing of our canonsburg , pennsylvania office , partially offset by a favorable adjustment to the lease obligation for our former tulsa , oklahoma office due to a change in estimated sub-lease rental income . 39 exploration the following table sets forth the components of exploration expenses for the periods presented : replace_table_token_49_th unproved leasehold amortization declined during 2012 as costs related to successful eagle ford shale wells were transferred to proved properties . geological and geophysical costs decreased during 2012 because our efforts in 2012 were concentrated on development drilling in the eagle ford shale whereas in 2011 we conducted exploratory prospect activities in multiple areas . dry hole costs in 2011 related to several unsuccessful wells in the mid-continent region . we also recorded drilling rig standby charges in 2011 in connection with the suspension of our exploratory drilling program in the marcellus shale . depreciation , depletion and amortization the following tables set forth the nature of the dd & a variances for the periods presented : replace_table_token_50_th the effect of lower overall production volumes on dd & a was more than offset by higher depletion rates associated with oil and ngl production . our average dd & a rate increased due primarily to higher capitalized finding and development costs attributable to our drilling program in the eagle ford shale as well as lower natural gas reserves due to revisions . impairments the following table summarizes the impairments recorded for the periods presented : replace_table_token_51_th in 2012 , we recognized a $ 28.4 million impairment of our appalachian natural gas assets triggered by the expected disposition of those properties , and a $ 75.0 million impairment of our marcellus shale assets due primarily to market declines in natural gas prices and the resultant reduction in proved natural gas reserves . in 2012 , we also recognized an impairment of certain tubular inventory and well materials triggered primarily by declines in asset quality . in 2011 , we recognized an impairment of our arkoma basin natural gas assets for $ 71.1 million , which was triggered by the expected disposition of those properties . also during 2011 , we recognized impairments of our horizontal coal bed methane properties in the appalachian region for $ 26.6

