however , there can be no assurance that more significant revisions will not be necessary in the future . significant downward revisions could result in an impairment representing a non-cash charge to income . in addition to the impact on calculation of the ceiling test , estimates of proved reserves are also a major component of the calculation of depletion . while the quantities of proved reserves require substantial judgment , the associated prices of oil and natural gas reserves that are included in the discounted present value of our reserves are objectively determined . the ceiling test calculation requires use of the unweighted arithmetic average of the first day of the month price during the 12-month period ending on the balance sheet date and costs in effect as of the last day of the accounting period , which are generally held constant for the life of the properties . as a result , the present value is not necessarily an indication of the fair value of the reserves . oil and natural gas prices have historically been volatile , and the prevailing prices at any given time may not reflect our partnership 's or the industry 's forecast of future prices . the preparation of financial statements in conformity with accounting principles generally accepted in the united states of america requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period . for example , estimates of uncollected revenues and unpaid expenses from royalty properties and npis operated by non-affiliated entities are particularly subjective due to the inability to gain accurate and timely information . therefore , actual results could differ from those estimates . please see “ item 1. business—customers and pricing ” and “ item 2. properties—royalty properties ” for additional discussion . contractual obligations our office lease in dallas , texas comprises our contractual obligations . payments due by period contractual obligations total less than 1 year 1-3 years 3-5 years more than 5 years operating lease obligations $ 326,000 $ 261,000 $ 65,000 23 results of operations normally , our period-to-period changes in net income and cash flows from operating activities are principally determined by changes in oil and natural gas sales volumes and prices , and to a lesser extent , by capital expenditures deducted under the npi calculation . our portion of oil and natural gas sales volumes and weighted average sales prices are shown in the following table . replace_table_token_12_th ( 1 ) provided to assist in determination of revenues ; applies only to net profits interests sales volumes prices . comparison of the twelve-month periods ended december 31 , 2013 , 2012 and 2011 royalty properties ' oil sales volumes increased 10.7 % from 327 mbbls during 2011 to 362 mbbls during 2012 , and then increased 4.7 % to 379 mbbls during 2013. these increases are primarily due to activity in the bakken trend which offset natural declines in other regions . royalty properties ' gas sales volumes decreased 3.3 % from 6,212 mmcf during 2011 to 6,007 mmcf during 2012 , and then decreased 15.9 % to 5,049 mmcf during 2013. the decreases in natural gas volumes between 2011 and 2012 were primarily due to reduced activity in fayetteville shale and barnett shale , while the decreases between 2012 and 2013 were primarily due to natural declines in the fayetteville shale and barnett shale . beginning in the third quarter of 2011 oil and gas sales volumes attributable to our npis included volumes attributable to the minerals npi . the minerals npi had cumulative revenues in excess of cumulative operating and development costs during the period ending september 30 , 2011. sales volumes and prices attributable to the minerals npi during periods prior to the third quarter of 2011 are excluded from the above table because the partnership did not receive any payments from such npi sales volumes during those prior periods . the amounts included in net profits income for the minerals npi properties for the years ended december 31 , 2011 , 2012 , and 2013 were $ 4,415,000 , $ 1,546,000 and $ 2,583,000 , respectively . see “ item 2 properties – net profits interest . ” npi properties ' oil sales volumes increased 92.5 % from 40 mbbls during 2011 to 77 mbbls during 2012 ; due to including the minerals npi and subsequently increased 81.8 % to 140 mbbls during 2013 due to continued activity in the bakken and permian regions . npi properties ' gas sales volumes increased 15.4 % from 3,838 mmcf during 2011 to 4,429 mmcf during 2012 ; principally due to including the minerals npi and subsequently decreased 7.2 % to 4,111 mmcf in 2013 due to natural declines in the fayetteville shale . the minerals npi oil sales volumes and gas sales volumes included in the net profits interest volumes were 31 mbbls and 713 mmcf , 65 mbbls and 1,480 mmcf , and 129 mbbls and 1,356 mmcf for years 2011 , 2012 , and 2013 , respectively . see “ item 2 properties – net profits interest . ” weighted average oil sales prices attributable to the royalty properties decreased 2.6 % from $ 91.55 per bbl in 2011 to $ 89.21 per bbl in 2012 and subsequently increased 5.5 % to $ 94.15 per bbl in 2013. royalty properties ' weighted average gas sales prices decreased 25.2 % from $ 3.77 per mcf during 2011 to $ 2.82 per mcf during 2012 and then increased 22.0 % to $ 3.44 per mcf during 2013. all such fluctuations resulted from changing market prices . story_separator_special_tag ” texas margin tax texas imposes a franchise tax ( commonly referred to as the texas margin tax ) at a rate of 1 % on gross revenues less certain deductions , as specifically set forth in the texas margin tax statute . the texas margin tax applies to corporations and limited liability companies , general and limited partnerships ( unless otherwise exempt ) , limited liability partnerships , trusts ( unless otherwise exempt ) , business trusts , business associations , professional associations , joint stock companies , holding companies , joint ventures and certain other business entities having limited liability protection . limited partnerships that receive at least 90 % of their gross income from designated passive sources , including royalties from mineral properties and other non-operated mineral interest income , and do not receive more than 10 % of their income from operating an active trade or business , are generally exempt from the texas margin tax as “ passive entities . ” we believe our partnership meets the requirements for being considered a “ passive entity ” for texas margin tax purposes and , therefore , it is exempt from the texas margin tax . if the partnership is exempt from texas margin tax as a passive entity , each unitholder that is considered a taxable entity under the texas margin tax would generally be required to include its portion of partnership revenues in its own texas margin tax computation . the texas administrative code provides such income is sourced according to the principal place of business of the partnership , which would be the state of texas . each unitholder is urged to consult an independent tax advisor regarding the requirements for filing state income , franchise and texas margin tax returns . 25 liquidity and capital resources capital resources our primary sources of capital are our cash flow from the royalty properties and the npis . we are not directly liable for the payment of any exploration , development or production costs . we do not have any transactions , arrangements or other relationships that could materially affect our liquidity or the sustainability of capital resources . pursuant to the terms of our partnership agreement , we can not incur indebtedness , other than trade payables , ( i ) in excess of $ 50,000 in the aggregate at any given time or ( ii ) which would constitute `` acquisition indebtedness `` ( as defined in section 514 of the internal revenue code of 1986 , as amended ) . our only cash requirements are the distributions of all our net cash flow to our unitholders , the payment of oil and natural gas production and property taxes not otherwise deducted from gross production revenues and general and administrative expenses incurred on our behalf and allocated in accordance with our partnership agreement . since the distributions to our unitholders are , by definition , determined after the payment of all expenses actually paid by us , the only cash requirements that may create liquidity concerns for us are the payments of expenses . since many of these expenses vary directly with oil and natural gas prices and sales volumes , such as production taxes , we anticipate that sufficient funds will be available at all times for payment of these expenses . of the expenses that do not vary with oil and natural gas prices and sales volumes , most are reimbursements to our general partner for allocable general and administrative costs including home office rent , salaries , and employee benefit plans . such reimbursements are generally limited to 5 % of an amount primarily based on annual distributions to our limited partners . historically , all such reimbursements have been substantially below the 5 % limit established by the partnership agreement . consequently , even during the 2008 economic downturn , our business risks were essentially limited to distribution amount decreases . see “ item 1. business – credit facilities and financing plans . ” see “ item 1a . risk factors – risks related to our business – cash distributions are affected by production and other costs , some of which are outside of our control . ” see “ item 1a . risk factors – risks inherent in an investment in our common units – cost reimbursement due our general partner may be substantial and reduce our cash available to distribute to our unitholders . `` see `` notes to consolidated financial statements – note 3 – related party transactions . `` off-balance sheet arrangements we have no significant off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition , changes in financial condition , revenues or expenses , results of operations , liquidity , capital expenditures or capital resources that are material to unitholders . expenses and capital expenditures depending upon gas prices , the operating partnership plans to continue its efforts to increase production in oklahoma by techniques that may include fracture treating , deepening , recompleting , and drilling . costs vary widely and are not predictable as each effort requires specific engineering . such activities by the operating partnership could influence the amount we receive from the npis as reflected in the accrual basis production costs $ /mcfe in the table under “ results of operations . ” the operating partnership owns and operates the wells , pipelines and natural gas compression and dehydration facilities on its properties located in kansas and oklahoma . the operating partnership does not anticipate incurring significant expense to replace these facilities at this time . these capital and operating costs are reflected in the npi payments we receive from the operating partnership . in 1998 , oklahoma regulations removed production quantity restrictions in the guymon-hugoton field and did not address efforts by third parties to persuade oklahoma to permit infill drilling in the guymon-hugoton field . infill drilling could

liquidity and working capital year-end cash and cash equivalents totaled $ 15,175,000 for 2013 , $ 13,792,000 for 2012 , and $ 14,238,000 for 2011 . 26 distributions distributions to limited partners and the general partner related to cash receipts for the period from october 2012 through december 2013 were as follows : replace_table_token_13_th in general , the limited partners are allocated 96 % of the royalty properties ' net receipts and 99 % of our npi net receipts . net profits interests we receive monthly payments from the operating partnership equal to 96.97 % of the net proceeds actually realized by the operating partnership from the properties underlying the net profits interests ( or “ npis ” ) . the operating partnership retains the 3.03 % balance of these net proceeds . net proceeds generally reflect gross proceeds attributable to oil and natural gas production actually received during the month less production costs actually paid during the same month . production costs generally reflect drilling , completion , operating and general and administrative costs and exclude depletion , amortization and other non-cash costs . the operating partnership made npi payments to us totaling $ 10,838,000 during october 2012 through september 2013 , which payments reflected 96.97 % of total net proceeds of $ 11,176,000 realized from september 2012 through august 2013. net proceeds realized by the operating partnership during september through november 2013 were reflected in npi payments made during october through december 2013. these payments were included in the fourth quarter distribution paid in early 2014 andare excluded from this 2013 analysis .


 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 working capital year-end cash and cash equivalents totaled $ 15,175,000 for 2013 , $ 13,792,000 for 2012 , and $ 14,238,000 for 2011 . 26 distributions distributions to limited partners and the general partner related to cash receipts for the period from october 2012 through december 2013 were as follows : replace_table_token_13_th in general , the limited partners are allocated 96 % of the royalty properties ' net receipts and 99 % of our npi net receipts . net profits interests we receive monthly payments from the operating partnership equal to 96.97 % of the net proceeds actually realized by the operating partnership from the properties underlying the net profits interests ( or “ npis ” ) . the operating partnership retains the 3.03 % balance of these net proceeds . net proceeds generally reflect gross proceeds attributable to oil and natural gas production actually received during the month less production costs actually paid during the same month . production costs generally reflect drilling , completion , operating and general and administrative costs and exclude depletion , amortization and other non-cash costs . the operating partnership made npi payments to us totaling $ 10,838,000 during october 2012 through september 2013 , which payments reflected 96.97 % of total net proceeds of $ 11,176,000 realized from september 2012 through august 2013. net proceeds realized by the operating partnership during september through november 2013 were reflected in npi payments made during october through december 2013. these payments were included in the fourth quarter distribution paid in early 2014 andare excluded from this 2013 analysis .
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 Suspicious Activity Report : however , there can be no assurance that more significant revisions will not be necessary in the future . significant downward revisions could result in an impairment representing a non-cash charge to income . in addition to the impact on calculation of the ceiling test , estimates of proved reserves are also a major component of the calculation of depletion . while the quantities of proved reserves require substantial judgment , the associated prices of oil and natural gas reserves that are included in the discounted present value of our reserves are objectively determined . the ceiling test calculation requires use of the unweighted arithmetic average of the first day of the month price during the 12-month period ending on the balance sheet date and costs in effect as of the last day of the accounting period , which are generally held constant for the life of the properties . as a result , the present value is not necessarily an indication of the fair value of the reserves . oil and natural gas prices have historically been volatile , and the prevailing prices at any given time may not reflect our partnership 's or the industry 's forecast of future prices . the preparation of financial statements in conformity with accounting principles generally accepted in the united states of america requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period . for example , estimates of uncollected revenues and unpaid expenses from royalty properties and npis operated by non-affiliated entities are particularly subjective due to the inability to gain accurate and timely information . therefore , actual results could differ from those estimates . please see “ item 1. business—customers and pricing ” and “ item 2. properties—royalty properties ” for additional discussion . contractual obligations our office lease in dallas , texas comprises our contractual obligations . payments due by period contractual obligations total less than 1 year 1-3 years 3-5 years more than 5 years operating lease obligations $ 326,000 $ 261,000 $ 65,000 23 results of operations normally , our period-to-period changes in net income and cash flows from operating activities are principally determined by changes in oil and natural gas sales volumes and prices , and to a lesser extent , by capital expenditures deducted under the npi calculation . our portion of oil and natural gas sales volumes and weighted average sales prices are shown in the following table . replace_table_token_12_th ( 1 ) provided to assist in determination of revenues ; applies only to net profits interests sales volumes prices . comparison of the twelve-month periods ended december 31 , 2013 , 2012 and 2011 royalty properties ' oil sales volumes increased 10.7 % from 327 mbbls during 2011 to 362 mbbls during 2012 , and then increased 4.7 % to 379 mbbls during 2013. these increases are primarily due to activity in the bakken trend which offset natural declines in other regions . royalty properties ' gas sales volumes decreased 3.3 % from 6,212 mmcf during 2011 to 6,007 mmcf during 2012 , and then decreased 15.9 % to 5,049 mmcf during 2013. the decreases in natural gas volumes between 2011 and 2012 were primarily due to reduced activity in fayetteville shale and barnett shale , while the decreases between 2012 and 2013 were primarily due to natural declines in the fayetteville shale and barnett shale . beginning in the third quarter of 2011 oil and gas sales volumes attributable to our npis included volumes attributable to the minerals npi . the minerals npi had cumulative revenues in excess of cumulative operating and development costs during the period ending september 30 , 2011. sales volumes and prices attributable to the minerals npi during periods prior to the third quarter of 2011 are excluded from the above table because the partnership did not receive any payments from such npi sales volumes during those prior periods . the amounts included in net profits income for the minerals npi properties for the years ended december 31 , 2011 , 2012 , and 2013 were $ 4,415,000 , $ 1,546,000 and $ 2,583,000 , respectively . see “ item 2 properties – net profits interest . ” npi properties ' oil sales volumes increased 92.5 % from 40 mbbls during 2011 to 77 mbbls during 2012 ; due to including the minerals npi and subsequently increased 81.8 % to 140 mbbls during 2013 due to continued activity in the bakken and permian regions . npi properties ' gas sales volumes increased 15.4 % from 3,838 mmcf during 2011 to 4,429 mmcf during 2012 ; principally due to including the minerals npi and subsequently decreased 7.2 % to 4,111 mmcf in 2013 due to natural declines in the fayetteville shale . the minerals npi oil sales volumes and gas sales volumes included in the net profits interest volumes were 31 mbbls and 713 mmcf , 65 mbbls and 1,480 mmcf , and 129 mbbls and 1,356 mmcf for years 2011 , 2012 , and 2013 , respectively . see “ item 2 properties – net profits interest . ” weighted average oil sales prices attributable to the royalty properties decreased 2.6 % from $ 91.55 per bbl in 2011 to $ 89.21 per bbl in 2012 and subsequently increased 5.5 % to $ 94.15 per bbl in 2013. royalty properties ' weighted average gas sales prices decreased 25.2 % from $ 3.77 per mcf during 2011 to $ 2.82 per mcf during 2012 and then increased 22.0 % to $ 3.44 per mcf during 2013. all such fluctuations resulted from changing market prices . story_separator_special_tag ” texas margin tax texas imposes a franchise tax ( commonly referred to as the texas margin tax ) at a rate of 1 % on gross revenues less certain deductions , as specifically set forth in the texas margin tax statute . the texas margin tax applies to corporations and limited liability companies , general and limited partnerships ( unless otherwise exempt ) , limited liability partnerships , trusts ( unless otherwise exempt ) , business trusts , business associations , professional associations , joint stock companies , holding companies , joint ventures and certain other business entities having limited liability protection . limited partnerships that receive at least 90 % of their gross income from designated passive sources , including royalties from mineral properties and other non-operated mineral interest income , and do not receive more than 10 % of their income from operating an active trade or business , are generally exempt from the texas margin tax as “ passive entities . ” we believe our partnership meets the requirements for being considered a “ passive entity ” for texas margin tax purposes and , therefore , it is exempt from the texas margin tax . if the partnership is exempt from texas margin tax as a passive entity , each unitholder that is considered a taxable entity under the texas margin tax would generally be required to include its portion of partnership revenues in its own texas margin tax computation . the texas administrative code provides such income is sourced according to the principal place of business of the partnership , which would be the state of texas . each unitholder is urged to consult an independent tax advisor regarding the requirements for filing state income , franchise and texas margin tax returns . 25 liquidity and capital resources capital resources our primary sources of capital are our cash flow from the royalty properties and the npis . we are not directly liable for the payment of any exploration , development or production costs . we do not have any transactions , arrangements or other relationships that could materially affect our liquidity or the sustainability of capital resources . pursuant to the terms of our partnership agreement , we can not incur indebtedness , other than trade payables , ( i ) in excess of $ 50,000 in the aggregate at any given time or ( ii ) which would constitute `` acquisition indebtedness `` ( as defined in section 514 of the internal revenue code of 1986 , as amended ) . our only cash requirements are the distributions of all our net cash flow to our unitholders , the payment of oil and natural gas production and property taxes not otherwise deducted from gross production revenues and general and administrative expenses incurred on our behalf and allocated in accordance with our partnership agreement . since the distributions to our unitholders are , by definition , determined after the payment of all expenses actually paid by us , the only cash requirements that may create liquidity concerns for us are the payments of expenses . since many of these expenses vary directly with oil and natural gas prices and sales volumes , such as production taxes , we anticipate that sufficient funds will be available at all times for payment of these expenses . of the expenses that do not vary with oil and natural gas prices and sales volumes , most are reimbursements to our general partner for allocable general and administrative costs including home office rent , salaries , and employee benefit plans . such reimbursements are generally limited to 5 % of an amount primarily based on annual distributions to our limited partners . historically , all such reimbursements have been substantially below the 5 % limit established by the partnership agreement . consequently , even during the 2008 economic downturn , our business risks were essentially limited to distribution amount decreases . see “ item 1. business – credit facilities and financing plans . ” see “ item 1a . risk factors – risks related to our business – cash distributions are affected by production and other costs , some of which are outside of our control . ” see “ item 1a . risk factors – risks inherent in an investment in our common units – cost reimbursement due our general partner may be substantial and reduce our cash available to distribute to our unitholders . `` see `` notes to consolidated financial statements – note 3 – related party transactions . `` off-balance sheet arrangements we have no significant off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition , changes in financial condition , revenues or expenses , results of operations , liquidity , capital expenditures or capital resources that are material to unitholders . expenses and capital expenditures depending upon gas prices , the operating partnership plans to continue its efforts to increase production in oklahoma by techniques that may include fracture treating , deepening , recompleting , and drilling . costs vary widely and are not predictable as each effort requires specific engineering . such activities by the operating partnership could influence the amount we receive from the npis as reflected in the accrual basis production costs $ /mcfe in the table under “ results of operations . ” the operating partnership owns and operates the wells , pipelines and natural gas compression and dehydration facilities on its properties located in kansas and oklahoma . the operating partnership does not anticipate incurring significant expense to replace these facilities at this time . these capital and operating costs are reflected in the npi payments we receive from the operating partnership . in 1998 , oklahoma regulations removed production quantity restrictions in the guymon-hugoton field and did not address efforts by third parties to persuade oklahoma to permit infill drilling in the guymon-hugoton field . infill drilling could

