v2.4.1.9
Document Entity Information Document (USD $)
12 Months Ended
Dec. 31, 2014
Feb. 27, 2015
Jun. 30, 2014
Entity Information      
Entity Registrant Name Rockies Region 2007 LP    
Entity Central Index Key 0001407805    
Current Fiscal Year End Date --12-31    
Entity Filer Category Smaller Reporting Company    
Document Type 10-K    
Document Period End Date Dec. 31, 2014    
Document Fiscal Year Focus 2014    
Document Fiscal Period Focus FY    
Amendment Flag false    
Entity Common Stock, Shares Outstanding   0.00dei_EntityCommonStockSharesOutstanding  
Additional General Partnership Units Outstanding   0.00pdce_AdditionalGeneralPartnershipUnitsOutstanding  
Entity Well-Known Seasoned Issuer No    
Entity Voluntary Filers No    
Entity Current Reporting Status Yes    
Entity Public Float     $ 0dei_EntityPublicFloat
v2.4.1.9
Balance Sheets Statement (USD $)
Dec. 31, 2014
Dec. 31, 2013
Current assets:    
Cash and cash equivalents $ 628,520us-gaap_CashAndCashEquivalentsAtCarryingValue $ 570,376us-gaap_CashAndCashEquivalentsAtCarryingValue
Accounts receivable 168,421us-gaap_AccountsReceivableNetCurrent 378,940us-gaap_AccountsReceivableNetCurrent
Crude oil inventory 37,394us-gaap_InventoryNet 55,308us-gaap_InventoryNet
Total current assets 834,335us-gaap_AssetsCurrent 1,004,624us-gaap_AssetsCurrent
Crude oil and natural gas properties, successful efforts method, at cost 15,661,273us-gaap_OilAndGasPropertySuccessfulEffortMethodGross 55,748,749us-gaap_OilAndGasPropertySuccessfulEffortMethodGross
Less: Accumulated depreciation, depletion and amortization (8,836,596)us-gaap_OilAndGasPropertySuccessfulEffortMethodAccumulatedDepreciationDepletionAndAmortization (31,819,541)us-gaap_OilAndGasPropertySuccessfulEffortMethodAccumulatedDepreciationDepletionAndAmortization
Crude oil and natural gas properties, net 6,824,677us-gaap_OilAndGasPropertySuccessfulEffortMethodNet 23,929,208us-gaap_OilAndGasPropertySuccessfulEffortMethodNet
Other assets 0us-gaap_OtherAssetsNoncurrent 89,630us-gaap_OtherAssetsNoncurrent
Total Assets 7,659,012us-gaap_Assets 25,023,462us-gaap_Assets
Current liabilities:    
Accounts payable and accrued expenses 19,545us-gaap_AccountsPayableCurrent 33,041us-gaap_AccountsPayableCurrent
Due to Managing General Partner-other, net 178,150us-gaap_DueToAffiliateCurrent 119,994us-gaap_DueToAffiliateCurrent
Total current liabilities 197,695us-gaap_LiabilitiesCurrent 153,035us-gaap_LiabilitiesCurrent
Asset retirement obligations 1,702,926us-gaap_AssetRetirementObligationsNoncurrent 935,813us-gaap_AssetRetirementObligationsNoncurrent
Total liabilities 1,900,621us-gaap_Liabilities 1,088,848us-gaap_Liabilities
Commitments and contingent liabilities      
Partners' equity:    
Managing General Partner (3,063,343)us-gaap_GeneralPartnersCapitalAccount 3,661,859us-gaap_GeneralPartnersCapitalAccount
Limited Partners - 4470 units issued and outstanding 8,821,734us-gaap_LimitedPartnersCapitalAccount 20,272,755us-gaap_LimitedPartnersCapitalAccount
Total Partners' equity 5,758,391us-gaap_PartnersCapital 23,934,614us-gaap_PartnersCapital
Total Liabilities and Partners' Equity $ 7,659,012us-gaap_LiabilitiesAndStockholdersEquity $ 25,023,462us-gaap_LiabilitiesAndStockholdersEquity
v2.4.1.9
Balance Sheet Parentheticals (Parentheticals)
Dec. 31, 2014
Dec. 31, 2013
Balance Sheet Parentheticals [Abstract]    
Limited Partners' Capital Account, Units Issued 4,470.00us-gaap_LimitedPartnersCapitalAccountUnitsIssued 4,470.00us-gaap_LimitedPartnersCapitalAccountUnitsIssued
Limited Partners' Capital Account, Units Outstanding 4,470.00us-gaap_LimitedPartnersCapitalAccountUnitsOutstanding 4,470.00us-gaap_LimitedPartnersCapitalAccountUnitsOutstanding
v2.4.1.9
Statements of Operations Statement (USD $)
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Revenues:    
Crude oil, natural gas and NGLs sales $ 3,544,226us-gaap_OilAndGasSalesRevenue $ 5,702,943us-gaap_OilAndGasSalesRevenue
Commodity price risk management gain (loss), net 0us-gaap_GainLossOnDerivativeInstrumentsNetPretax (417,689)us-gaap_GainLossOnDerivativeInstrumentsNetPretax
Total revenues 3,544,226us-gaap_Revenues 5,285,254us-gaap_Revenues
Operating costs and expenses:    
Crude oil, natural gas and NGLs production costs 972,963us-gaap_OilAndGasProductionExpense 1,395,391us-gaap_OilAndGasProductionExpense
Direct costs - general and administrative 171,338us-gaap_GeneralAndAdministrativeExpense 209,500us-gaap_GeneralAndAdministrativeExpense
Depreciation, depletion and amortization 2,289,410us-gaap_DepreciationDepletionAndAmortization 3,121,340us-gaap_DepreciationDepletionAndAmortization
Accretion of asset retirement obligations 73,793pdce_AccretionOfAssetRetirementObligationsFromContinuingOperations 68,266pdce_AccretionOfAssetRetirementObligationsFromContinuingOperations
Impairment of crude oil and natural gas properties 15,760,688us-gaap_ResultsOfOperationsImpairmentOfOilAndGasProperties 0us-gaap_ResultsOfOperationsImpairmentOfOilAndGasProperties
Total operating costs and expenses 19,268,192us-gaap_CostsAndExpenses 4,794,497us-gaap_CostsAndExpenses
Income (loss) from continuing operations (15,723,966)us-gaap_IncomeLossFromContinuingOperationsBeforeIncomeTaxesMinorityInterestAndIncomeLossFromEquityMethodInvestments 490,757us-gaap_IncomeLossFromContinuingOperationsBeforeIncomeTaxesMinorityInterestAndIncomeLossFromEquityMethodInvestments
Income from discontinued operations 0us-gaap_DiscontinuedOperationIncomeLossFromDiscontinuedOperationBeforeIncomeTax 43,679us-gaap_DiscontinuedOperationIncomeLossFromDiscontinuedOperationBeforeIncomeTax
Net income (loss) (15,723,966)us-gaap_ProfitLoss 534,436us-gaap_ProfitLoss
Income (loss) from continuing operations (15,723,966)us-gaap_IncomeLossFromContinuingOperationsBeforeIncomeTaxesMinorityInterestAndIncomeLossFromEquityMethodInvestments 490,757us-gaap_IncomeLossFromContinuingOperationsBeforeIncomeTaxesMinorityInterestAndIncomeLossFromEquityMethodInvestments
Less: Managing General Partner interest in net income (loss) from continuing operations (5,817,867)us-gaap_NetIncomeLossAllocatedToGeneralPartners 181,580us-gaap_NetIncomeLossAllocatedToGeneralPartners
Net income (loss) allocated to Investor Partners (9,906,099)us-gaap_NetIncomeLossAllocatedToLimitedPartners 309,177us-gaap_NetIncomeLossAllocatedToLimitedPartners
Net income (loss) per Investor Partner unit, Continuing operations $ (2,216)us-gaap_IncomeLossFromContinuingOperationsPerOutstandingLimitedPartnershipAndGeneralPartnershipUnitBasicAndDiluted $ 69us-gaap_IncomeLossFromContinuingOperationsPerOutstandingLimitedPartnershipAndGeneralPartnershipUnitBasicAndDiluted
Investor Partner units outstanding 4,470.00us-gaap_LimitedPartnersCapitalAccountUnitsOutstanding 4,470.00us-gaap_LimitedPartnersCapitalAccountUnitsOutstanding
Managing General Partner    
Operating costs and expenses:    
Income from discontinued operations 0us-gaap_DiscontinuedOperationIncomeLossFromDiscontinuedOperationBeforeIncomeTax
/ us-gaap_StatementEquityComponentsAxis
= us-gaap_GeneralPartnerMember
16,161us-gaap_DiscontinuedOperationIncomeLossFromDiscontinuedOperationBeforeIncomeTax
/ us-gaap_StatementEquityComponentsAxis
= us-gaap_GeneralPartnerMember
Net income per Investor Partner unit, Discontinued operations $ 0us-gaap_IncomeLossFromDiscontinuedOperationsNetOfTaxPerOutstandingLimitedPartnershipAndGeneralPartnershipUnitBasicAndDiluted
/ us-gaap_StatementEquityComponentsAxis
= us-gaap_GeneralPartnerMember
$ 6us-gaap_IncomeLossFromDiscontinuedOperationsNetOfTaxPerOutstandingLimitedPartnershipAndGeneralPartnershipUnitBasicAndDiluted
/ us-gaap_StatementEquityComponentsAxis
= us-gaap_GeneralPartnerMember
Limited Partner [Member]    
Operating costs and expenses:    
Income from discontinued operations $ 0us-gaap_DiscontinuedOperationIncomeLossFromDiscontinuedOperationBeforeIncomeTax
/ us-gaap_StatementEquityComponentsAxis
= us-gaap_LimitedPartnerMember
$ 27,518us-gaap_DiscontinuedOperationIncomeLossFromDiscontinuedOperationBeforeIncomeTax
/ us-gaap_StatementEquityComponentsAxis
= us-gaap_LimitedPartnerMember
Net income (loss) per Investor Partner unit $ (2,216)us-gaap_NetIncomeLossPerOutstandingLimitedPartnershipUnitBasicNetOfTax
/ us-gaap_StatementEquityComponentsAxis
= us-gaap_LimitedPartnerMember
$ 75us-gaap_NetIncomeLossPerOutstandingLimitedPartnershipUnitBasicNetOfTax
/ us-gaap_StatementEquityComponentsAxis
= us-gaap_LimitedPartnerMember
v2.4.1.9
Statement of Partners' Equity Statement (USD $)
Total
Investor Partners
Managing General Partner
Balance at Dec. 31, 2012 $ 44,263,746us-gaap_PartnersCapital $ 33,080,108us-gaap_PartnersCapital
/ us-gaap_PartnerCapitalComponentsAxis
= us-gaap_LimitedPartnerMember
$ 11,183,638us-gaap_PartnersCapital
/ us-gaap_PartnerCapitalComponentsAxis
= us-gaap_GeneralPartnerMember
Change in Partners' Equity:      
Distributions to Partners (20,863,568)us-gaap_PartnersCapitalAccountDistributions (13,144,048)us-gaap_PartnersCapitalAccountDistributions
/ us-gaap_PartnerCapitalComponentsAxis
= us-gaap_LimitedPartnerMember
(7,719,520)us-gaap_PartnersCapitalAccountDistributions
/ us-gaap_PartnerCapitalComponentsAxis
= us-gaap_GeneralPartnerMember
Net income (loss) 534,436us-gaap_IncomeLossFromContinuingOperationsIncludingPortionAttributableToNoncontrollingInterest 336,695us-gaap_IncomeLossFromContinuingOperationsIncludingPortionAttributableToNoncontrollingInterest
/ us-gaap_PartnerCapitalComponentsAxis
= us-gaap_LimitedPartnerMember
197,741us-gaap_IncomeLossFromContinuingOperationsIncludingPortionAttributableToNoncontrollingInterest
/ us-gaap_PartnerCapitalComponentsAxis
= us-gaap_GeneralPartnerMember
Balance at Dec. 31, 2013 23,934,614us-gaap_PartnersCapital 20,272,755us-gaap_PartnersCapital
/ us-gaap_PartnerCapitalComponentsAxis
= us-gaap_LimitedPartnerMember
3,661,859us-gaap_PartnersCapital
/ us-gaap_PartnerCapitalComponentsAxis
= us-gaap_GeneralPartnerMember
Change in Partners' Equity:      
Distributions to Partners (2,452,257)us-gaap_PartnersCapitalAccountDistributions (1,544,922)us-gaap_PartnersCapitalAccountDistributions
/ us-gaap_PartnerCapitalComponentsAxis
= us-gaap_LimitedPartnerMember
(907,335)us-gaap_PartnersCapitalAccountDistributions
/ us-gaap_PartnerCapitalComponentsAxis
= us-gaap_GeneralPartnerMember
Net income (loss) (15,723,966)us-gaap_IncomeLossFromContinuingOperationsIncludingPortionAttributableToNoncontrollingInterest (9,906,099)us-gaap_IncomeLossFromContinuingOperationsIncludingPortionAttributableToNoncontrollingInterest
/ us-gaap_PartnerCapitalComponentsAxis
= us-gaap_LimitedPartnerMember
(5,817,867)us-gaap_IncomeLossFromContinuingOperationsIncludingPortionAttributableToNoncontrollingInterest
/ us-gaap_PartnerCapitalComponentsAxis
= us-gaap_GeneralPartnerMember
Balance at Dec. 31, 2014 $ 5,758,391us-gaap_PartnersCapital $ 8,821,734us-gaap_PartnersCapital
/ us-gaap_PartnerCapitalComponentsAxis
= us-gaap_LimitedPartnerMember
$ (3,063,343)us-gaap_PartnersCapital
/ us-gaap_PartnerCapitalComponentsAxis
= us-gaap_GeneralPartnerMember
v2.4.1.9
Statements of Cash Flows Statement (USD $)
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Cash flows from operating activities:    
Net income (loss) $ (15,723,966)us-gaap_ProfitLoss $ 534,436us-gaap_ProfitLoss
Adjustments to net income (loss) to reconcile to net cash from operating activities:    
Depreciation, depletion and amortization 2,289,410us-gaap_AccumulatedDepreciationDepletionAndAmortizationPropertyPlantAndEquipmentPeriodIncreaseDecrease 3,276,550us-gaap_AccumulatedDepreciationDepletionAndAmortizationPropertyPlantAndEquipmentPeriodIncreaseDecrease
Accretion of asset retirement obligations 73,793us-gaap_AssetRetirementObligationAccretionExpense 75,144us-gaap_AssetRetirementObligationAccretionExpense
Net change in fair value of unsettled derivatives 0us-gaap_UnrealizedGainLossOnDerivativesAndCommodityContracts 1,693,233us-gaap_UnrealizedGainLossOnDerivativesAndCommodityContracts
Loss on sale of crude oil and natural gas properties 0us-gaap_GainLossOnSaleOfPropertyPlantEquipment 495,574us-gaap_GainLossOnSaleOfPropertyPlantEquipment
Impairment of crude oil and natural gas properties 15,760,688us-gaap_ImpairmentOfOilAndGasProperties 0us-gaap_ImpairmentOfOilAndGasProperties
Changes in assets and liabilities:    
Accounts receivable 210,519us-gaap_IncreaseDecreaseInAccountsReceivable 487,004us-gaap_IncreaseDecreaseInAccountsReceivable
Crude oil inventory 17,914us-gaap_IncreaseDecreaseInInventories (17,283)us-gaap_IncreaseDecreaseInInventories
Other assets 89,630us-gaap_IncreaseDecreaseInOtherOperatingAssets (42,919)us-gaap_IncreaseDecreaseInOtherOperatingAssets
Accounts payable and accrued expenses (13,496)us-gaap_IncreaseDecreaseInAccountsPayableAndAccruedLiabilities (57,529)us-gaap_IncreaseDecreaseInAccountsPayableAndAccruedLiabilities
Due to Managing General Partner-other, net 58,156us-gaap_IncreaseDecreaseInDueToAffiliatesCurrent 130,241us-gaap_IncreaseDecreaseInDueToAffiliatesCurrent
Due from Managing General Partner-other, net 0us-gaap_IncreaseDecreaseInDueFromAffiliatesCurrent 800,598us-gaap_IncreaseDecreaseInDueFromAffiliatesCurrent
Net cash from operating activities 2,762,648us-gaap_NetCashProvidedByUsedInOperatingActivities 7,375,049us-gaap_NetCashProvidedByUsedInOperatingActivities
Cash flows from investing activities:    
Capital expenditures for crude oil and natural gas properties (252,247)us-gaap_PaymentsToAcquireOilAndGasEquipment 0us-gaap_PaymentsToAcquireOilAndGasEquipment
Proceeds from sale of crude oil and natural gas properties 0us-gaap_ProceedsFromSaleOfOilAndGasPropertyAndEquipment 13,488,519us-gaap_ProceedsFromSaleOfOilAndGasPropertyAndEquipment
Net cash from investing activities (252,247)us-gaap_NetCashProvidedByUsedInInvestingActivities 13,488,519us-gaap_NetCashProvidedByUsedInInvestingActivities
Cash flows from financing activities:    
Distributions to Partners (2,452,257)us-gaap_PartnersCapitalAccountDistributions (20,863,568)us-gaap_PartnersCapitalAccountDistributions
Net cash from financing activities (2,452,257)us-gaap_NetCashProvidedByUsedInFinancingActivities (20,863,568)us-gaap_NetCashProvidedByUsedInFinancingActivities
Net change in cash and cash equivalents 58,144us-gaap_CashAndCashEquivalentsPeriodIncreaseDecrease 0us-gaap_CashAndCashEquivalentsPeriodIncreaseDecrease
Cash and cash equivalents, beginning of period 570,376us-gaap_CashAndCashEquivalentsAtCarryingValue 570,376us-gaap_CashAndCashEquivalentsAtCarryingValue
Cash and cash equivalents, end of period 628,520us-gaap_CashAndCashEquivalentsAtCarryingValue 570,376us-gaap_CashAndCashEquivalentsAtCarryingValue
Supplemental disclosure of non-cash activity:    
Change in asset retirement obligation, with corresponding change in crude oil and natural gas properties, net of disposal $ 693,320us-gaap_IncreaseDecreaseInAssetRetirementObligations $ (249,424)us-gaap_IncreaseDecreaseInAssetRetirementObligations
v2.4.1.9
General and Basis of Presentation
12 Months Ended
Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]
GENERAL

Rockies Region 2007 Limited Partnership was organized in 2007 as a limited partnership, in accordance with the laws of the State of West Virginia, for the purpose of engaging in the exploration and development of crude oil and natural gas properties. Business operations commenced upon closing of an offering for the private placement of Partnership units. Upon funding, this Partnership entered into a D&O Agreement with the Managing General Partner which authorizes PDC to conduct and manage this Partnership's business. In accordance with the terms of the Agreement, the Managing General Partner is authorized to manage all activities of this Partnership and initiates and completes substantially all Partnership transactions.

As of December 31, 2014, there were 1,777 Investor Partners in this Partnership. PDC is the designated Managing General Partner of this Partnership and owns a 37% Managing General Partner ownership in this Partnership. According to the terms of the Agreement, revenues, costs and cash distributions of this Partnership are allocated 63% to the Investor Partners, which are shared pro rata based upon the number of units in this Partnership, and 37% to the Managing General Partner. The Managing General Partner may repurchase Investor Partner units under certain circumstances provided by the Agreement, upon request of an individual Investor Partner. For more information about the Managing General Partner's limited partner unit repurchase program, see Note 8, Partners' Equity and Cash Distributions. Through December 31, 2014, the Managing General Partner had repurchased 73.0 units of Partnership interests from the Investor Partners at an average price of $3,961 per unit. As of December 31, 2014, the Managing General Partner owned 38.0% of this Partnership.

The preparation of this Partnership's financial statements in accordance with U.S. GAAP requires the Managing General Partner to make estimates and assumptions that affect the amounts reported in this Partnership's financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to this Partnership's financial statements include estimates of crude oil, natural gas and NGLs sales revenue, crude oil, natural gas and NGLs reserves and impairment of proved properties.
v2.4.1.9
Summary of Significant Accounting Policies
12 Months Ended
Dec. 31, 2014
Accounting Policies [Abstract]  
Significant Accounting Policies [Text Block]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The financial statements include only those assets, liabilities and results of operations of the partners which relate to the business of this Partnership.

Cash and Cash Equivalents. This Partnership considers all highly liquid investments with original maturities of three months or less to be cash equivalents. This Partnership maintains substantially all of its cash and cash equivalents in a bank account at one financial institution. The balance in this Partnership's account is insured by Federal Deposit Insurance Corporation, up to $250,000. This Partnership has not experienced losses in any such accounts to date and limits this Partnership's exposure to credit loss by placing its cash and cash equivalents with a high-quality financial institution.

Accounts Receivable and Allowance for Doubtful Accounts. This Partnership's accounts receivable are from purchasers of crude oil, natural gas and NGLs. This Partnership sells substantially all of its crude oil, natural gas and NGLs to customers who purchase crude oil, natural gas and NGLs from other partnerships managed by this Partnership's Managing General Partner. The Managing General Partner periodically reviews accounts receivable for credit risks resulting from changes in the financial condition of its customers. In making the estimate for receivables that are uncollectible, the Managing General Partner considers, among other things, subsequent collections, historical write-offs and overall creditworthiness of this Partnership's customers. It is reasonably possible that the Managing General Partner's estimate of uncollectible receivables will change periodically. Historically, neither PDC, nor any of the other partnerships managed by this Partnership's Managing General Partner, have experienced significant losses from uncollectible accounts receivable.

Commitments. As Managing General Partner, PDC maintains performance bonds in the form of certificates of deposit for plugging, reclaiming and abandoning of this Partnership's wells as required by governmental agencies. If a government agency were required to access these performance bonds to cover plugging, reclaiming or abandonment costs on a Partnership well, this Partnership would be obligated to fund any amounts in excess of funds previously withheld by the Managing General Partner to cover these expenses.

Inventory. Inventory consists of crude oil, stated at the lower of cost to produce or market.

Derivative Financial Instruments. This Partnership is exposed to the effect of market fluctuations in the prices of crude oil and natural gas. The Managing General Partner previously employed established policies and procedures to manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. All derivative assets and liabilities were previously recorded on the balance sheets at fair value. PDC, as Managing General Partner, elected not to designate any of this Partnership's derivative instruments as hedges. Accordingly, changes in the fair value of this Partnership's derivative instruments were recorded in this Partnership's statements of operations and this Partnership's net income was subject to greater volatility than it would have been if this Partnership's derivative instruments had qualified for hedge accounting. The net settlements and the net change in fair value of unsettled derivatives are recorded in the line item captioned, “Commodity price risk management loss, net.” As positions designated to this Partnership settled, positive and negative settlements were netted for distribution. Positive settlements were paid to this Partnership and negative settlements were deducted from this Partnership's cash distributions generated from production. This Partnership bore its proportionate share of counterparty risk. As of December 31, 2014 and 2013, this Partnership had no outstanding derivative instruments.

Crude Oil and Natural Gas Properties. This Partnership accounts for its crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. This Partnership calculates quarterly DD&A expense by using estimated prior period-end reserves as the denominator, with the exception of this Partnership's fourth quarter where this Partnership uses the year-end reserve estimate adjusted to add back fourth quarter production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized in the statement of operations as a gain or loss. Upon the sale of individual wells, the proceeds are credited to accumulated DD&A. See Supplemental Crude Oil, Natural Gas and NGLs Information - Unaudited, Net Proved Reserves, included at the end of these financial statements and accompanying notes elsewhere in this report for additional information regarding this Partnership's reserve reporting. In accordance with the Agreement, all capital contributed to this Partnership, after deducting syndication costs and a one-time management fee, was used solely for the drilling of crude oil and natural gas wells. This Partnership does not maintain an inventory of undrilled leases.

Proved Reserves. Partnership estimates of proved reserves are based on those quantities of crude oil, natural gas and NGLs which, by analysis of geoscience and engineering data, are estimated with reasonable certainty to be economically producible in the future from known reservoirs under existing conditions, operating methods and government regulations. Annually, the Managing General Partner engages independent petroleum engineers to prepare a reserve and economic evaluation of this Partnership's properties on a well-by-well basis as of December 31. Additionally, this Partnership adjusts reserves for major well rework or abandonment during the year, as needed. The process of estimating and evaluating crude oil, natural gas and NGLs reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates represent this Partnership's most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect this Partnership's DD&A expense, a change in this Partnership's estimated reserves could have an effect on this Partnership's net income or loss.

Proved Property Impairment. Upon a triggering event, this Partnership assesses its producing crude oil and natural gas properties for possible impairment by comparing net capitalized costs, or carrying value, to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which the Managing General Partner reasonably estimates the commodities to be sold. The estimates of future prices may differ from current market prices of crude oil and natural gas. Certain events, including but not limited to, downward revisions in estimates to this Partnership's reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event and, therefore, a possible impairment of this Partnership's proved crude oil and natural gas properties. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis and is measured by the amount by which the net capitalized costs exceed their fair value. Impairment charges are included in the statement of operations line item "Impairment of crude oil and natural gas properties", with a corresponding reduction to "Crude oil and natural gas properties" and "Accumulated depreciation, depletion and amortization" line items on the balance sheets.

Production Tax Liability. Production tax liability represents estimated taxes, primarily severance, ad valorem and property, to be paid to the states and counties in which this Partnership produces crude oil, natural gas and NGLs. This Partnership's share of these taxes recorded in the line item "Crude oil, natural gas and NGLs production costs" on this Partnership's statements of operations. This Partnership's production taxes payable are included in the caption accounts payable and accrued expenses on this Partnership's balance sheets.

Income Taxes. Since the taxable income or loss of this Partnership is reported in the separate tax returns of the individual investor partners, no provision has been made for income taxes by this Partnership.

Asset Retirement Obligations. This Partnership accounts for asset retirement obligations by recording the fair value of Partnership well plugging and abandonment obligations when incurred, which is at the time the well is spud. Upon initial recognition of an asset retirement obligation, this Partnership increases the carrying amount of the long-lived asset by the same amount as the liability. Over time, the liabilities are accreted for the change in present value. The initial capitalized costs, net of salvage value, are depleted over the useful lives of the related assets through charges to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from changes in retirement costs or the estimated timing of settling asset retirement obligations. See Note 6, Asset Retirement Obligations, for a reconciliation of the changes in this Partnership's asset retirement obligation.

Revenue Recognition. Crude oil, natural gas and NGLs revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. This Partnership currently uses the “net-back” method of accounting for transportation and processing arrangements of this Partnership's sales pursuant to which the transportation and/or processing is provided by or through the purchaser. Under these arrangements, the Managing General Partner sells this Partnership's natural gas at the wellhead and recognizes revenues based on the wellhead sales price since transportation and processing costs downstream of the wellhead are incurred by this Partnership's purchasers and reflected in the wellhead price. The majority of this Partnership's natural gas and NGLs is sold by the Managing General Partner on a long-term basis, primarily over the life of the well. Virtually all of the Managing General Partner's contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line and the quality of the natural gas.

Recent Accounting Standards

Recently Issued Accounting Standard. In April 2014, the Financial Accounting Standards Board issued changes related to the criteria for determining which disposals can be presented as discontinued operations and modified related disclosure requirements. Under the new pronouncement, a discontinued operation is defined as a disposal of a component of an organization that represents a strategic shift and that has a major effect on the organization's operations and financial results. These changes are to be applied prospectively for new disposals or components of this Partnership's business classified as held for sale during interim and annual periods beginning after December 15, 2014, with early adoption permitted. Adoption of this guidance is not expected to have a significant impact on this Partnership's financial statements.

In May 2014, the FASB and the International Accounting Standards Board ("IASB") issued their converged standard on revenue recognition that provides a single, comprehensive model that entities will apply to determine the measurement of revenue and timing of when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The standard outlines a five-step approach to apply the underlying principle: (a) identify the contract with the customer (b) identify the separate performance obligations in the contract (c) determine the transaction price (d) allocate the transaction price to separate performance obligations and (e) recognize revenue when (or as) each performance obligation is satisfied. The revenue standard is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period, and can be adopted under the full retrospective method or simplified transition method. Early adoption is not permitted. The Managing General Partner of this Partnership is currently evaluating the impact these changes will have on this Partnership's financial statements.

In August 2014, the FASB issued a new standard related to the disclosure of uncertainties about an entity's ability to continue as a going concern. The new standard will explicitly require management to assess an entity's ability to continue as a going concern every reporting period and to provide related footnote disclosures in certain circumstances. The new standard will be effective for all entities in the first annual period ending after December 15, 2016, with early adoption permitted. The Managing General Partner of this Partnership is currently evaluating the impact these changes will have on this Partnership's financial statements.

In January 2015, the FASB issued new accounting guidance eliminating from current accounting guidance the concept of extraordinary items, which, among other things, required an entity to segregate extraordinary items considered to be unusual and infrequent from the results of ordinary operations and show the item separately in the income statement, net of tax, after income from continuing operations. This guidance is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. Adoption of this guidance is not expected to have a significant impact on this Partnership's financial statements.
v2.4.1.9
Fair Value of Financial Instruments
12 Months Ended
Dec. 31, 2014
Fair Value Disclosures [Abstract]  
Fair Value Disclosures [Text Block]
FAIR VALUE OF FINANCIAL INSTRUMENTS

This Partnership's fair value measurements were estimated pursuant to a fair value hierarchy that requires this Partnership to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. In these cases, the lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels.
v2.4.1.9
Derivative Financial Instruments
12 Months Ended
Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Derivative Instruments Disclosure [Text Block]
DERIVATIVE FINANCIAL INSTRUMENTS

This Partnership had no crude oil, natural gas or NGLs derivative activity subsequent to June 30, 2013 as all open positions were liquidated prior to that date. The following tables present the impact of this Partnership's derivative instruments on this Partnership's accompanying statements of operations:
 
 
Year Ended
Statement of operations line item:
 
December 31, 2013
Commodity price risk management loss, net
 
 
Net settlements
 
$
1,275,544

Net change in fair value of unsettled derivatives
 
(1,693,233
)
Total commodity price risk management loss, net
 
$
(417,689
)


Currently, the Managing General Partner does not anticipate entering into derivative instruments for any of this Partnership's future production. The Managing General Partner's policy prohibits the use of crude oil and natural gas derivative instruments for speculative purposes.
v2.4.1.9
Concentration of Risk
12 Months Ended
Dec. 31, 2014
Risks and Uncertainties [Abstract]  
Concentration Risk Disclosure [Text Block]
CONCENTRATION OF RISK

Accounts Receivable. This Partnership's accounts receivable are from purchasers of crude oil, natural gas and NGLs production. This Partnership sells substantially all of its crude oil, natural gas and NGLs to customers who purchase crude oil, natural gas and NGLs from other partnerships managed by this Partnership's Managing General Partner. Inherent to this Partnership's industry is the concentration of crude oil, natural gas and NGLs sales to a limited number of customers. This industry concentration has the potential to impact this Partnership's overall exposure to credit risk in that its customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions.

As of December 31, 2014 and 2013, this Partnership did not record an allowance for doubtful accounts and did not incur any losses on accounts receivable. As of December 31, 2014, this Partnership had three customers representing 10% or more of the accounts receivable balance: Concord Energy, LLC, DCP Midstream, LP and Suncor Energy Marketing, Inc., represented 58%, 27% and 15%, respectively.

Major Customers. The following table presents the individual customers from continuing operations constituting 10% or more of total revenues:
 
 
Year ended December 31,
Major Customer
 
2014
 
2013
Suncor Energy Marketing, Inc.
 
53%
 
82%
DCP Midstream, LP
 
24%
 
18%
Concord Energy, LLC
 
23%
 
—%
v2.4.1.9
Asset Retirement Obligations
12 Months Ended
Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]  
Asset Retirement Obligation Disclosure [Text Block]
ASSET RETIREMENT OBLIGATIONS

The following table presents the changes in carrying amounts of the asset retirement obligations associated with this Partnership's working interest in crude oil and natural gas properties:

 
Year Ended December 31,
 
2014
 
2013
 
 
 
 
Balance at beginning of period
$
935,813

 
$
1,110,093

Revisions in estimated cash flows (1)
693,320

 

Obligations discharged with divestiture of properties (2)

 
(249,424
)
Accretion expense
73,793

 
75,144

Balance at end of period
$
1,702,926

 
$
935,813



(1)
The revisions in estimated cash flows during 2014 were due to changes in estimates of costs for materials and services related to the plugging and abandonment of certain wells in the Wattenberg Field, as well as a decrease in the estimated useful life of these wells. The increase in estimated costs is primarily the result of various recent federal, state and local laws that regulate plugging operations and techniques. The revision in the asset retirement obligation did not have an immediate effect in the 2014 statement of operations as the increase in the revised obligation was offset by a capitalized amount, which will be depreciated over the useful lives of respective wells.
(2)
This Partnership's asset retirement obligations related to Piceance Basin assets were discharged with the sale of these assets during the year ended December 31, 2013. See Note 11, Divestiture and Discontinued Operations, for further information regarding the divestiture of the Piceance Basin assets.
v2.4.1.9
Commitments and Contingencies
12 Months Ended
Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]  
Commitments and Contingencies Disclosure [Text Block]
COMMITMENTS AND CONTINGENCIES

Legal Proceedings

Neither this Partnership nor PDC, in its capacity as the Managing General Partner of this Partnership, are party to any pending legal proceeding that PDC believes would have a materially adverse effect on this Partnership's business, financial condition, results of operations or liquidity.

Environmental

Due to the nature of the oil and gas industry, this Partnership is exposed to environmental risks. The Managing General Partner has various policies and procedures in place to prevent environmental contamination and mitigate the risks from environmental contamination. The Managing General Partner conducts periodic reviews to identify changes in this Partnership's environmental risk profile. Liabilities are accrued when environmental remediation efforts are probable and the costs can be reasonably estimated. These liabilities are reduced as remediation efforts are completed or are adjusted as a consequence of subsequent periodic reviews.

During the year ended December 31, 2014, as a result of the Managing General Partner's periodic review, no new environmental remediation projects were identified and this Partnership's expense for environmental remediation efforts was not significant. This Partnership had no liabilities for environmental remediation efforts as of December 31, 2014 and December 31, 2013.

The Managing General Partner is not currently aware of any environmental claims existing as of December 31, 2014 which have not been provided for or would otherwise have a material impact on this Partnership's financial statements; however, there can be no assurance that current regulatory requirements will not change or unknown past non-compliance with environmental laws or other potential sources of liability will not be discovered on this Partnership's properties.
v2.4.1.9
Partners' Equity and Cash Distributions
12 Months Ended
Dec. 31, 2014
Equity [Abstract]  
Partners' Capital Notes Disclosure [Text Block]
PARTNERS' EQUITY AND CASH DISTRIBUTIONS

Partners' Equity

Limited Partner Units. A limited partner unit represents the individual interest of an individual investor partner in this Partnership. No public market exists or will develop for the units. While units of this Partnership are transferable, assignability of the units is limited, requiring the consent of the Managing General Partner. Further, individual investor partners may request that the Managing General Partner repurchase units pursuant to the unit repurchase program described below.

Allocation of Partners' Interest. The following table presents the participation of the Investor Partners and the Managing General Partner in the revenues and costs of this Partnership:
 
 
 
 
Managing
 
 
Investor
 
General
 
 
Partners
 
Partner
Partnership Revenue:
 
 
 
 
Crude oil, natural gas and NGLs sales
 
63
%
 
37
%
Commodity price risk management gain (loss)
 
63
%
 
37
%
Sale of productive properties
 
63
%
 
37
%
Sale of equipment
 
63
%
 
37
%
Interest income
 
63
%
 
37
%
 
 
 
 
 
Partnership Operating Costs and Expenses:
 
 
 
 
Crude oil, natural gas and NGLs production and well
 
 
 
 
operations costs (a)
 
63
%
 
37
%
Depreciation, depletion and amortization expense
 
63
%
 
37
%
Accretion of asset retirement obligations
 
63
%
 
37
%
Direct costs - general and administrative (b)
 
63
%
 
37
%


(a)
Represents operating costs incurred after the completion of productive wells, including monthly per-well charges paid to the Managing General Partner.
(b)
The Managing General Partner receives monthly reimbursement from this Partnership for direct costs - general and administrative incurred by the Managing General Partner on behalf of this Partnership.

Unit Repurchase Provisions. Investor Partners may request that the Managing General Partner repurchase limited partnership units at any time beginning with the third anniversary of the first cash distribution of this Partnership. The repurchase price is set at a minimum of four times the most recent 12 months of cash distributions from production. In any calendar year, the Managing General Partner is conditionally obligated to purchase Investor Partner units aggregating up to 10% of the initial subscriptions, if requested by an individual investor partner, subject to PDC's financial ability to do so and upon receipt of opinions of counsel that the repurchase will not cause this Partnership to be treated as a “publicly traded partnership” or result in the termination of this Partnership for federal income tax purposes. If accepted, repurchase requests are fulfilled by the Managing General Partner on a first-come, first-served basis.

Cash Distributions

The Agreement requires the Managing General Partner to distribute cash available for distribution no less frequently than quarterly. Historically, the Managing General Partner has made distributions of Partnership cash on a monthly basis, if funds have been available for distribution. The Managing General Partner makes cash distributions of 63% to the Investor Partners and 37% to the Managing General Partner. Cash distributions began in May 2008. The following table presents the cash distributions made to the Investor Partners and Managing General Partner during the years indicated:
 
 
Year Ended December 31,
 
 
2014
 
2013
 
 
 
 
 
Cash distributions
 
$
2,452,257

 
$
20,863,568



Cash distributions decreased in 2014 compared to 2013, primarily due to the July 2013 distribution of $13.5 million of the proceeds received for the Piceance Basin asset divestiture. See Note 11, Divestiture and Discontinued Operations, for additional details related to the divestiture of this Partnership's Piceance Basin assets.
v2.4.1.9
Transactions with Managing General Partner
12 Months Ended
Dec. 31, 2014
Related Party Transactions [Abstract]  
Related Party Transactions Disclosure [Text Block]
TRANSACTIONS WITH MANAGING GENERAL PARTNER

The Managing General Partner transacts business on behalf of this Partnership under the authority of the D&O Agreement. Revenues and other cash inflows received by the Managing General Partner on behalf of this Partnership are distributed to the partners, net of corresponding operating costs and other cash outflows incurred on behalf of this Partnership.

The following table presents transactions with the Managing General Partner reflected in the balance sheets line item “Due to Managing General Partner-other, net” which remain undistributed or unsettled with this Partnership's investors as of the dates indicated:

    
 
As of December 31,
 
2014
 
2013
Crude oil, natural gas and NGLs sales revenues
collected from this Partnership's third-party customers
$
219,542

 
$
306,014

Other (1)
(397,692
)
 
(426,008
)
Total Due to Managing General Partner-other, net
$
(178,150
)
 
$
(119,994
)

(1)
All other unsettled transactions between this Partnership and the Managing General Partner, the majority of which are operating costs and general and administrative costs which have not been deducted from distributions.

The following table presents Partnership transactions with the Managing General Partner for the years ended December 31, 2014 and 2013. “Well operations and maintenance” and “Gathering, compression and processing fees” are included in the “Crude oil, natural gas and NGLs production costs” line item on the statements of operations for continuing operations or in Note 11, Divestiture and Discontinued Operations, for information on discontinued operations.    
 
Year Ended December 31,
 
2014
 
2013
 Well operations and maintenance (1)
$
836,856

 
$
1,660,093

 Gathering, compression and processing fees (2)

 
119,017

 Direct costs - general and administrative (3)
171,338

 
535,551

 Cash distributions (4)
929,282

 
7,819,797


(1) Under the D&O Agreement, the Managing General Partner, as operator of the wells, receives payments for well charges and lease operating supplies and maintenance expenses from this Partnership when the wells begin producing.
Well charges. The Managing General Partner receives reimbursement at actual cost for all direct expenses incurred on behalf of this Partnership, monthly well operating charges for operating and maintaining the wells during producing operations, which reflects a competitive field rate, and a monthly administration charge for Partnership activities.
Under the D&O Agreement, PDC provides all necessary labor, vehicles, supervision, management, accounting and overhead services for normal production operations, and may deduct from Partnership revenues a fixed monthly charge for these services. The charge for these operations and field supervision fees (referred to as “well tending fees”) for each producing well is based on competitive industry field rates, which vary based on areas of operation. The well tending fees and administration fees may be adjusted annually to an amount equal to the rates initially established by the D&O Agreement multiplied by the then current average of the Oil and Gas Extraction Index and the Professional and Technical Services Index, as published by the United States Department of Labor, Bureau of Labor Statistics, provided that the charge may not exceed the rate which would be charged by comparable operators in the area of operations. This average is commonly referred to as the Accounting Procedure Wage Index Adjustment which is published annually by the Council of Petroleum Accountants Societies. These rates are reflective of similar costs incurred by comparable operators in the production field. PDC, in certain circumstances, has and may in the future, provide equipment or supplies, perform salt water disposal services and other services for this Partnership at the lesser of cost or competitive prices in the area of operations.
The Managing General Partner as operator bills non-routine operations and administration costs to this Partnership at its cost. The Managing General Partner may not benefit by inter-positioning itself between this Partnership and the actual provider of operator services. In no event is any consideration received for operator services duplicative of any consideration or reimbursement received under the Agreement.
The well operating, or well tending, charges cover all normal and regularly recurring operating expenses for the production, delivery and sale of crude oil, natural gas and NGLs, such as:
well tending, routine maintenance and adjustment;
reading meters, recording production, pumping, maintaining appropriate books and records; and
preparing production related reports to this Partnership and government agencies.

The well supervision fees do not include costs and expenses related to:

the purchase or repairs of equipment, materials or third-party services;
the cost of compression and third-party gathering services, or gathering costs;
brine disposal; or
rebuilding of access roads.
These costs are charged at the invoice cost of the materials purchased or the third-party services performed.
Lease operating supplies and maintenance expense. The Managing General Partner may enter into other transactions with this Partnership for services, supplies and equipment during the production phase of this Partnership, and is entitled to compensation at competitive prices and terms as determined by reference to charges of unaffiliated companies providing similar services, supplies and equipment. Management believes these transactions were on terms no less favorable than could have been obtained from non-affiliated third parties.
(2) Under the Agreement, the Managing General Partner is responsible for gathering, compression, processing and transporting the natural gas produced by this Partnership to interstate pipeline systems, local distribution companies and/or end-users in the area from the point the natural gas from the well is commingled with natural gas from other wells. In such a case, the Managing General Partner uses gathering systems already owned by PDC or PDC constructs the necessary facilities if no such line exists. In such a case, this Partnership pays a gathering, compression and processing fee directly to the Managing General Partner at competitive rates. If a third-party gathering system is used, this Partnership pays the gathering fee charged by the third-party gathering the natural gas.
(3) The Managing General Partner is reimbursed by this Partnership for all direct costs expended on this Partnership’s behalf for administrative and professional fees, such as legal expenses, audit fees and engineering fees for reserve reports.
(4) The Agreement provides for the allocation of cash distributions 63% to the Investors Partners and 37% to the Managing General Partner. The Investor Partner cash distributions during the years ended December 31, 2014 and 2013 include $21,947 and $100,277, respectively, related to equity cash distributions for Investor Partner units that have been repurchased by PDC. For additional disclosure regarding the allocation of cash distributions, refer to Note 8, Partners’ Equity and Cash Distributions.
v2.4.1.9
Impairment of Capitalized Costs
12 Months Ended
Dec. 31, 2014
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]  
Impairment of crude oil and natural gas properties [Table Text Block]
IMPAIRMENT OF CRUDE OIL AND NATURAL GAS PROPERTIES

In December 2014, this Partnership recognized an impairment charge of approximately $15.8 million to write-down its Wattenberg Field proved oil and natural gas properties. The impairment charge represented the amount by which the carrying value of the Wattenberg Field crude oil and natural gas properties exceeded the estimated fair value, and was therefore not recoverable. The estimated fair value was determined based on estimated future discounted net cash flows, a Level 3 input, using estimated production and prices at which the Managing General Partner reasonably expects this Partnership's crude oil and natural gas will be sold. See Supplemental Crude Oil, Natural Gas and NGLs Information–Unaudited–Capitalized Costs and Costs Incurred in Crude Oil and Natural Gas Property Development Activities for additional information on impairment of crude oil and natural gas properties.
v2.4.1.9
Divestitures and Discontinued Operations Divestitures and Discontinued Operations (Notes)
12 Months Ended
Dec. 31, 2014
Discontinued Operations and Disposal Groups [Abstract]  
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]
DIVESTITURE AND DISCONTINUED OPERATIONS

Piceance Basin. In February 2013, this Partnership's Managing General Partner entered into a purchase and sale agreement pursuant to which this Partnership agreed to sell to an unrelated third-party all of its Piceance Basin assets and certain derivatives. In June 2013, this divestiture was completed with total consideration for this Partnership of approximately $13.5 million. The divestiture of this Partnership's Piceance Basin assets resulted in a decrease of crude oil and natural gas properties of $23.8 million and a decrease of accumulated depreciation, depletion and amortization of $10.3 million. The sale resulted in a loss on divestiture of assets of approximately $0.5 million, which is included in discontinued operations.
In July 2013, this Partnership distributed proceeds received for the Piceance Basin asset divestiture to the Managing General Partner and Investor Partners as follows:
 
 
Amount
Distributed to:
 
(millions)
 
 
 
Managing General Partner
 
$
5.0

Investor Partners
 
8.5

Total
 
$
13.5

 
 
 

Following the sale, this Partnership does not have a significant continuing involvement in the operations of, or cash flows from, the Piceance Basin oil and gas properties. Accordingly, the results of operations related to these assets have been separately reported as discontinued operations in the statement of operations for all periods presented.
The following table presents statement of operations data related to this Partnership's discontinued operations for the Piceance Basin divestiture:
 
 
Year Ended
Statement of Operations - Discontinued Operations
 
December 31, 2013
 
 
 
Revenues:
 
 
Crude oil, natural gas and NGLs sales
 
$
1,771,961

 
 
 
Operating costs and expenses:
 
 
Crude oil, natural gas and NGLs production costs
 
744,569

Direct costs - general and administrative expense
 
326,051

Depreciation, depletion and amortization
 
155,210

Accretion of asset retirement obligations
 
6,878

Loss on sale of crude oil and natural gas properties
 
495,574

Total operating costs and expenses
 
1,728,282

 
 
 
Income from discontinued operations
 
$
43,679

 
 
 


While the reclassification of revenues and expenses related to discontinued operations for the prior period had no impact upon previously reported net earnings, the statement of operations table presents the revenues and expenses that were reclassified from the specified statement of operations line items to discontinued operations.
v2.4.1.9
Supplemental Crude Oil, Natural Gas and NGL Information - Unaudited
12 Months Ended
Dec. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]  
Oil and Gas Exploration and Production Industries Disclosures [Text Block]
Net Proved Reserves

This Partnership utilized the services of an independent petroleum engineer, Ryder Scott, to estimate this Partnership's 2014 and 2013 crude oil, natural gas and NGLs reserves. These reserve estimates have been prepared in compliance with professional standards and the reserves definitions prescribed by the SEC.

Proved reserves estimates may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change. This Partnership's net proved reserve estimates have been adjusted as necessary to reflect all contractual agreements, royalty obligations and interests owned by others at the time of the estimate. Proved developed reserves are the quantities of crude oil, natural gas and NGLs expected to be recovered from currently producing zones under the continuation of present operating methods. Proved undeveloped reserves are those reserves expected to be recovered from existing wells where a relatively major expenditure is required for additional reserve development. As of December 31, 2014 and 2013, there are no proved undeveloped reserves for this Partnership.

This Partnership's estimated proved developed non-producing reserves consist entirely of reserves attributable to the Wattenberg Field's additional development. These additional development activities, part of the Additional Development Plan, generally occur five to 10 years after initial well drilling. Additional Development Plan activities are suspended until pipeline capacity improves. The time frame for development activity is impacted by individual well decline curves as well as the plan to maximize the financial impact of the additional development.

The following table presents the prices used to estimate this Partnership's reserves, by commodity:

 
 
Price Used to Estimate Reserves (1)
As of December 31,
 
Crude Oil (per Bbl)
 
Natural Gas (per Mcf)
 
NGLs (per Bbl)
2014
 
$
84.33

 
$
3.92

 
$
25.53

2013
 
81.91

 
3.38

 
23.14



(1)
The prices used to estimate reserves have been prepared in accordance with the SEC. Future estimated cash flows were based on a 12-month average price calculated as the unweighted arithmetic average of the prices on the first day of each month, January through December, applied to this Partnership's year-end estimated proved reserves. Prices for each of the two years were adjusted for Btu content, transportation and regional price differences.

The following table presents the changes in estimated quantities of this Partnership's reserves, all of which are located within the United States:
 
Natural Gas
 
NGLs
 
Crude Oil and Condensate
 
Crude Oil Equivalent
 
(MMcf)
 
(MBbl)
 
(MBbl)
 
(MBoe)
Proved Reserves:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proved reserves, January 1, 2013 (1)
13,036

 
595

 
853

 
3,621

Revisions of previous estimates and reclassifications
(712
)
 
(74
)
 
(117
)
 
(310
)
Dispositions (1)
(6,874
)
 

 
(15
)
 
(1,161
)
Production
(734
)
 
(22
)
 
(53
)
 
(197
)
Proved reserves, December 31, 2013
4,716

 
499

 
668

 
1,953

 
 
 
 
 
 
 
 
Revisions of previous estimates and reclassifications
(1,285
)
 
(100
)
 
(180
)
 
(494
)
Production
(132
)
 
(17
)
 
(33
)
 
(72
)
Proved reserves, December 31, 2014
3,299

 
382

 
455

 
1,387

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proved Developed Reserves, as of:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2013
4,716

 
499

 
668

 
1,953

December 31, 2014
3,299

 
382

 
455

 
1,387

 
 
 
 
 
 
 
 

(1)
Includes estimated reserve data related to this Partnership's Piceance Basin assets. In June 2013, this Partnership's Piceance Basin crude oil and natural gas properties were divested. See Note 11, Divestiture and Discontinued Operations, for additional information regarding this divestiture. As of January 1, 2013, total proved reserves related to this Partnership's Piceance Basin assets include 7,390 MMcf of natural gas and 17 MBbl of crude oil, for an aggregate of 1,249 MBoe of crude oil equivalent.

2014 Activity. As of December 31, 2014, this Partnership recorded a downward revision of its previous estimate of proved reserves by approximately 494 MBoe. The revision includes downward revisions to previous estimates of 1,285 MMcf of natural gas, 100 MBbl of NGLs and 180 MBbl of crude oil. The downward revisions were the result of reduced asset performance. There were no proved undeveloped reserves developed in 2014. There were no proved undeveloped reserves attributable to this Partnership's assets as of December 31, 2014.

2013 Activity. As of December 31, 2013, this Partnership recorded a downward revision of its previous estimate of proved reserves by approximately 310 MBoe. The revision includes downward revisions to previous estimates of 712 MMcf of natural gas, 74 MBbl of NGLs and 117 MBbl of crude oil. The downward revisions were the result of lower pricing, reduced asset performance and a reduction in proved non-producing reserves. There was a significant increase to the differential to NYMEX. A portion of non-producing reserves were reclassified from proved to probable due to not being economically producible. The outcome of these three items significantly decreased estimated reserves. The divestiture of this Partnership's Piceance Basin assets resulted in the disposition of reserves comprised of 6,874 MMcf of natural gas and 15 MBbl of crude oil. There were no proved undeveloped reserves developed in 2013. There were no proved undeveloped reserves attributable to this Partnership's assets as of December 31, 2013.
  
Capitalized Costs and Costs Incurred in Crude Oil and Natural Gas Property Development Activities

Crude oil and natural gas development costs include costs incurred to gain access to and prepare development well locations for drilling, drill and equip developmental wells, complete additional production formations or recomplete existing production formations and provide facilities to extract, treat, gather and store crude oil and natural gas.

This Partnership is engaged solely in crude oil and natural gas activities, all of which are located in the continental United States. Drilling operations began upon funding in August 2007. This Partnership currently owns an undivided working interest in 75 gross (73.9 net) productive crude oil and natural gas wells located in the Wattenberg Field within the Denver-Julesburg Basin, north and east of Denver, Colorado.

Aggregate capitalized costs related to crude oil and natural gas development and production activities with applicable accumulated DD&A are presented below:
 
 As of December 31,
 
2014
 
2013
Leasehold costs
$
509,093

 
$
1,965,081

Development costs (1)
15,152,180

 
53,783,668

Crude oil and natural gas properties, successful efforts method, at cost
15,661,273

 
55,748,749

Less: Accumulated DD&A
(8,836,596
)
 
(31,819,541
)
Crude oil and natural gas properties, net
$
6,824,677

 
$
23,929,208



(1)
Includes estimated costs associated with this Partnership's asset retirement obligations. See Note 6, Asset Retirement Obligations, for further information.

From time-to-time, this Partnership invests in additional equipment which supports treatment, delivery and measurement of crude oil and natural gas or environmental protection. This Partnership may also invest in equipment and services to complete refracturing or recompletion opportunities pursuant to the Additional Development Plan. Substantially all of the $0.3 million investment in 2014 was for equipment and services. There were no investments for this Partnership in 2013.

This Partnership recorded an impairment charge of $15.8 million for the year ended December 31, 2014. Accordingly, this Partnership reduced crude oil and natural gas properties by $41.1 million and related accumulated depreciation, depletion and amortization for those properties by $25.3 million as of December 31, 2014. See Note 10, Impairment of Crude Oil and Natural Gas Properties, for additional disclosure related to this Partnership's proved property impairments.
v2.4.1.9
Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Policies)
12 Months Ended
Dec. 31, 2014
Accounting Policies [Abstract]  
Use of Estimates, Policy [Policy Text Block]
The preparation of this Partnership's financial statements in accordance with U.S. GAAP requires the Managing General Partner to make estimates and assumptions that affect the amounts reported in this Partnership's financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to this Partnership's financial statements include estimates of crude oil, natural gas and NGLs sales revenue, crude oil, natural gas and NGLs reserves and impairment of proved properties.
Basis of Accounting, Policy [Policy Text Block]
The financial statements include only those assets, liabilities and results of operations of the partners which relate to the business of this Partnership.
Cash and Cash Equivalents, Policy [Policy Text Block]
This Partnership considers all highly liquid investments with original maturities of three months or less to be cash equivalents. This Partnership maintains substantially all of its cash and cash equivalents in a bank account at one financial institution
Receivables, Policy [Policy Text Block]
accounts receivable are from purchasers of crude oil, natural gas and NGLs. This Partnership sells substantially all of its crude oil, natural gas and NGLs to customers who purchase crude oil, natural gas and NGLs from other partnerships managed by this Partnership's Managing General Partner. The Managing General Partner periodically reviews accounts receivable for credit risks resulting from changes in the financial condition of its customers. In making the estimate for receivables that are uncollectible, the Managing General Partner considers, among other things, subsequent collections, historical write-offs and overall creditworthiness of this Partnership's customers
Inventory, Policy [Policy Text Block]
Inventory consists of crude oil, stated at the lower of cost to produce or market
Derivatives, Policy [Policy Text Block]
All derivative assets and liabilities were previously recorded on the balance sheets at fair value. PDC, as Managing General Partner, elected not to designate any of this Partnership's derivative instruments as hedges. Accordingly, changes in the fair value of this Partnership's derivative instruments were recorded in this Partnership's statements of operations and this Partnership's net income was subject to greater volatility than it would have been if this Partnership's derivative instruments had qualified for hedge accounting. The net settlements and the net change in fair value of unsettled derivatives are recorded in the line item captioned, “Commodity price risk management loss, net.” As positions designated to this Partnership settled, positive and negative settlements were netted for distribution. Positive settlements were paid to this Partnership and negative settlements were deducted from this Partnership's cash distributions generated from production.
Oil and Gas Properties Policy [Policy Text Block]
This Partnership accounts for its crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. This Partnership calculates quarterly DD&A expense by using estimated prior period-end reserves as the denominator, with the exception of this Partnership's fourth quarter where this Partnership uses the year-end reserve estimate adjusted to add back fourth quarter production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized in the statement of operations as a gain or loss. Upon the sale of individual wells, the proceeds are credited to accumulated DD&A. See Supplemental Crude Oil, Natural Gas and NGLs Information - Unaudited, Net Proved Reserves, included at the end of these financial statements and accompanying notes elsewhere in this report for additional information regarding this Partnership's reserve reporting. In accordance with the Agreement, all capital contributed to this Partnership, after deducting syndication costs and a one-time management fee, was used solely for the drilling of crude oil and natural gas wells. This Partnership does not maintain an inventory of undrilled leases.

Proved Reserves. Partnership estimates of proved reserves are based on those quantities of crude oil, natural gas and NGLs which, by analysis of geoscience and engineering data, are estimated with reasonable certainty to be economically producible in the future from known reservoirs under existing conditions, operating methods and government regulations. Annually, the Managing General Partner engages independent petroleum engineers to prepare a reserve and economic evaluation of this Partnership's properties on a well-by-well basis as of December 31. Additionally, this Partnership adjusts reserves for major well rework or abandonment during the year, as needed. The process of estimating and evaluating crude oil, natural gas and NGLs reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates represent this Partnership's most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect this Partnership's DD&A expense, a change in this Partnership's estimated reserves could have an effect on this Partnership's net income or loss.

Property, Plant and Equipment, Impairment [Policy Text Block]
this Partnership assesses its producing crude oil and natural gas properties for possible impairment by comparing net capitalized costs, or carrying value, to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which the Managing General Partner reasonably estimates the commodities to be sold. The estimates of future prices may differ from current market prices of crude oil and natural gas. Certain events, including but not limited to, downward revisions in estimates to this Partnership's reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event and, therefore, a possible impairment of this Partnership's proved crude oil and natural gas properties. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis and is measured by the amount by which the net capitalized costs exceed their fair value.
Production Tax Liability, Policy [Policy Text Block]
Production tax liability represents estimated taxes, primarily severance, ad valorem and property, to be paid to the states and counties in which this Partnership produces crude oil, natural gas and NGLs. This Partnership's share of these taxes recorded in the line item "Crude oil, natural gas and NGLs production costs" on this Partnership's statements of operations. This Partnership's production taxes payable are included in the caption accounts payable and accrued expenses on this Partnership's balance sheets.
Asset Retirement Obligations, Policy [Policy Text Block]
This Partnership accounts for asset retirement obligations by recording the fair value of Partnership well plugging and abandonment obligations when incurred, which is at the time the well is spud. Upon initial recognition of an asset retirement obligation, this Partnership increases the carrying amount of the long-lived asset by the same amount as the liability. Over time, the liabilities are accreted for the change in present value. The initial capitalized costs, net of salvage value, are depleted over the useful lives of the related assets through charges to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from changes in retirement costs or the estimated timing of settling asset retirement obligations.
Revenue Recognition, Policy [Policy Text Block]
revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. This Partnership currently uses the “net-back” method of accounting for transportation and processing arrangements of this Partnership's sales pursuant to which the transportation and/or processing is provided by or through the purchaser. Under these arrangements, the Managing General Partner sells this Partnership's natural gas at the wellhead and recognizes revenues based on the wellhead sales price since transportation and processing costs downstream of the wellhead are incurred by this Partnership's purchasers and reflected in the wellhead price. The majority of this Partnership's natural gas and NGLs is sold by the Managing General Partner on a long-term basis, primarily over the life of the well. Virtually all of the Managing General Partner's contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line and the quality of the natural gas.
Accounting Standards Recently Adopted [Policy Text Block]
In April 2014, the Financial Accounting Standards Board issued changes related to the criteria for determining which disposals can be presented as discontinued operations and modified related disclosure requirements. Under the new pronouncement, a discontinued operation is defined as a disposal of a component of an organization that represents a strategic shift and that has a major effect on the organization's operations and financial results. These changes are to be applied prospectively for new disposals or components of this Partnership's business classified as held for sale during interim and annual periods beginning after December 15, 2014, with early adoption permitted. Adoption of this guidance is not expected to have a significant impact on this Partnership's financial statements.

In May 2014, the FASB and the International Accounting Standards Board ("IASB") issued their converged standard on revenue recognition that provides a single, comprehensive model that entities will apply to determine the measurement of revenue and timing of when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The standard outlines a five-step approach to apply the underlying principle: (a) identify the contract with the customer (b) identify the separate performance obligations in the contract (c) determine the transaction price (d) allocate the transaction price to separate performance obligations and (e) recognize revenue when (or as) each performance obligation is satisfied. The revenue standard is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period, and can be adopted under the full retrospective method or simplified transition method. Early adoption is not permitted. The Managing General Partner of this Partnership is currently evaluating the impact these changes will have on this Partnership's financial statements.

In August 2014, the FASB issued a new standard related to the disclosure of uncertainties about an entity's ability to continue as a going concern. The new standard will explicitly require management to assess an entity's ability to continue as a going concern every reporting period and to provide related footnote disclosures in certain circumstances. The new standard will be effective for all entities in the first annual period ending after December 15, 2016, with early adoption permitted. The Managing General Partner of this Partnership is currently evaluating the impact these changes will have on this Partnership's financial statements.

In January 2015, the FASB issued new accounting guidance eliminating from current accounting guidance the concept of extraordinary items, which, among other things, required an entity to segregate extraordinary items considered to be unusual and infrequent from the results of ordinary operations and show the item separately in the income statement, net of tax, after income from continuing operations. This guidance is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. Adoption of this guidance is not expected to have a significant impact on this Partnership's financial statements.
v2.4.1.9
Derivative Financial Instruments Derivative Financial Instruments (Tables)
12 Months Ended
Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]
The following tables present the impact of this Partnership's derivative instruments on this Partnership's accompanying statements of operations:
 
 
Year Ended
Statement of operations line item:
 
December 31, 2013
Commodity price risk management loss, net
 
 
Net settlements
 
$
1,275,544

Net change in fair value of unsettled derivatives
 
(1,693,233
)
Total commodity price risk management loss, net
 
$
(417,689
)
v2.4.1.9
Concentration of Risk Concentration of Risk (Tables)
12 Months Ended
Dec. 31, 2014
Concentration Risk - Revenue  
Individual Customers Constituting 10% or more of Total Revenue [Table Text Block]
Major Customers. The following table presents the individual customers from continuing operations constituting 10% or more of total revenues:
 
 
Year ended December 31,
Major Customer
 
2014
 
2013
Suncor Energy Marketing, Inc.
 
53%
 
82%
DCP Midstream, LP
 
24%
 
18%
Concord Energy, LLC
 
23%
 
—%
v2.4.1.9
Asset Retirement Obligations Asset Retirement Obligations (Tables)
12 Months Ended
Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]  
Schedule of Change in Asset Retirement Obligation [Table Text Block]
The following table presents the changes in carrying amounts of the asset retirement obligations associated with this Partnership's working interest in crude oil and natural gas properties:

 
Year Ended December 31,
 
2014
 
2013
 
 
 
 
Balance at beginning of period
$
935,813

 
$
1,110,093

Revisions in estimated cash flows (1)
693,320

 

Obligations discharged with divestiture of properties (2)

 
(249,424
)
Accretion expense
73,793

 
75,144

Balance at end of period
$
1,702,926

 
$
935,813



(1)
The revisions in estimated cash flows during 2014 were due to changes in estimates of costs for materials and services related to the plugging and abandonment of certain wells in the Wattenberg Field, as well as a decrease in the estimated useful life of these wells. The increase in estimated costs is primarily the result of various recent federal, state and local laws that regulate plugging operations and techniques. The revision in the asset retirement obligation did not have an immediate effect in the 2014 statement of operations as the increase in the revised obligation was offset by a capitalized amount, which will be depreciated over the useful lives of respective wells.
(2)
This Partnership's asset retirement obligations related to Piceance Basin assets were discharged with the sale of these assets during the year ended December 31, 2013. See Note 11, Divestiture and Discontinued Operations, for further information regarding the divestiture of the Piceance Basin assets.
v2.4.1.9
Partners' Equity and Cash Distributions (Tables)
12 Months Ended
Dec. 31, 2014
Allocation of Partners' Interest  
Allocation of Partner Interest [Table Text Block]
Allocation of Partners' Interest. The following table presents the participation of the Investor Partners and the Managing General Partner in the revenues and costs of this Partnership:
 
 
 
 
Managing
 
 
Investor
 
General
 
 
Partners
 
Partner
Partnership Revenue:
 
 
 
 
Crude oil, natural gas and NGLs sales
 
63
%
 
37
%
Commodity price risk management gain (loss)
 
63
%
 
37
%
Sale of productive properties
 
63
%
 
37
%
Sale of equipment
 
63
%
 
37
%
Interest income
 
63
%
 
37
%
 
 
 
 
 
Partnership Operating Costs and Expenses:
 
 
 
 
Crude oil, natural gas and NGLs production and well
 
 
 
 
operations costs (a)
 
63
%
 
37
%
Depreciation, depletion and amortization expense
 
63
%
 
37
%
Accretion of asset retirement obligations
 
63
%
 
37
%
Direct costs - general and administrative (b)
 
63
%
 
37
%


(a)
Represents operating costs incurred after the completion of productive wells, including monthly per-well charges paid to the Managing General Partner.
(b)
The Managing General Partner receives monthly reimbursement from this Partnership for direct costs - general and administrative incurred by the Managing General Partner on behalf of this Partnership.
v2.4.1.9
Partners' Equity and Cash Distributions Cash Distributions (Tables)
12 Months Ended
Dec. 31, 2014
Distributions made to limited partner and managing partner of limited partnership. [Line Items]  
Distributions Made to Limited Partner, by Distribution [Table Text Block]
The following table presents the cash distributions made to the Investor Partners and Managing General Partner during the years indicated:
 
 
Year Ended December 31,
 
 
2014
 
2013
 
 
 
 
 
Cash distributions
 
$
2,452,257

 
$
20,863,568

v2.4.1.9
Transactions with Managing General Partner Transactions with Managing General Partner (Tables)
12 Months Ended
Dec. 31, 2014
Related Party Transactions [Abstract]  
Due from (to) Managing General Partner-other, net [Table Text Block]
The following table presents transactions with the Managing General Partner reflected in the balance sheets line item “Due to Managing General Partner-other, net” which remain undistributed or unsettled with this Partnership's investors as of the dates indicated:

    
 
As of December 31,
 
2014
 
2013
Crude oil, natural gas and NGLs sales revenues
collected from this Partnership's third-party customers
$
219,542

 
$
306,014

Other (1)
(397,692
)
 
(426,008
)
Total Due to Managing General Partner-other, net
$
(178,150
)
 
$
(119,994
)

(1)
All other unsettled transactions between this Partnership and the Managing General Partner, the majority of which are operating costs and general and administrative costs which have not been deducted from distributions.

Schedule of Related Party Transactions [Table Text Block]
The following table presents Partnership transactions with the Managing General Partner for the years ended December 31, 2014 and 2013. “Well operations and maintenance” and “Gathering, compression and processing fees” are included in the “Crude oil, natural gas and NGLs production costs” line item on the statements of operations for continuing operations or in Note 11, Divestiture and Discontinued Operations, for information on discontinued operations.    
 
Year Ended December 31,
 
2014
 
2013
 Well operations and maintenance (1)
$
836,856

 
$
1,660,093

 Gathering, compression and processing fees (2)

 
119,017

 Direct costs - general and administrative (3)
171,338

 
535,551

 Cash distributions (4)
929,282

 
7,819,797


(1) Under the D&O Agreement, the Managing General Partner, as operator of the wells, receives payments for well charges and lease operating supplies and maintenance expenses from this Partnership when the wells begin producing.
Well charges. The Managing General Partner receives reimbursement at actual cost for all direct expenses incurred on behalf of this Partnership, monthly well operating charges for operating and maintaining the wells during producing operations, which reflects a competitive field rate, and a monthly administration charge for Partnership activities.
Under the D&O Agreement, PDC provides all necessary labor, vehicles, supervision, management, accounting and overhead services for normal production operations, and may deduct from Partnership revenues a fixed monthly charge for these services. The charge for these operations and field supervision fees (referred to as “well tending fees”) for each producing well is based on competitive industry field rates, which vary based on areas of operation. The well tending fees and administration fees may be adjusted annually to an amount equal to the rates initially established by the D&O Agreement multiplied by the then current average of the Oil and Gas Extraction Index and the Professional and Technical Services Index, as published by the United States Department of Labor, Bureau of Labor Statistics, provided that the charge may not exceed the rate which would be charged by comparable operators in the area of operations. This average is commonly referred to as the Accounting Procedure Wage Index Adjustment which is published annually by the Council of Petroleum Accountants Societies. These rates are reflective of similar costs incurred by comparable operators in the production field. PDC, in certain circumstances, has and may in the future, provide equipment or supplies, perform salt water disposal services and other services for this Partnership at the lesser of cost or competitive prices in the area of operations.
The Managing General Partner as operator bills non-routine operations and administration costs to this Partnership at its cost. The Managing General Partner may not benefit by inter-positioning itself between this Partnership and the actual provider of operator services. In no event is any consideration received for operator services duplicative of any consideration or reimbursement received under the Agreement.
The well operating, or well tending, charges cover all normal and regularly recurring operating expenses for the production, delivery and sale of crude oil, natural gas and NGLs, such as:
well tending, routine maintenance and adjustment;
reading meters, recording production, pumping, maintaining appropriate books and records; and
preparing production related reports to this Partnership and government agencies.

The well supervision fees do not include costs and expenses related to:

the purchase or repairs of equipment, materials or third-party services;
the cost of compression and third-party gathering services, or gathering costs;
brine disposal; or
rebuilding of access roads.
These costs are charged at the invoice cost of the materials purchased or the third-party services performed.
Lease operating supplies and maintenance expense. The Managing General Partner may enter into other transactions with this Partnership for services, supplies and equipment during the production phase of this Partnership, and is entitled to compensation at competitive prices and terms as determined by reference to charges of unaffiliated companies providing similar services, supplies and equipment. Management believes these transactions were on terms no less favorable than could have been obtained from non-affiliated third parties.
(2) Under the Agreement, the Managing General Partner is responsible for gathering, compression, processing and transporting the natural gas produced by this Partnership to interstate pipeline systems, local distribution companies and/or end-users in the area from the point the natural gas from the well is commingled with natural gas from other wells. In such a case, the Managing General Partner uses gathering systems already owned by PDC or PDC constructs the necessary facilities if no such line exists. In such a case, this Partnership pays a gathering, compression and processing fee directly to the Managing General Partner at competitive rates. If a third-party gathering system is used, this Partnership pays the gathering fee charged by the third-party gathering the natural gas.
(3) The Managing General Partner is reimbursed by this Partnership for all direct costs expended on this Partnership’s behalf for administrative and professional fees, such as legal expenses, audit fees and engineering fees for reserve reports.
(4) The Agreement provides for the allocation of cash distributions 63% to the Investors Partners and 37% to the Managing General Partner. The Investor Partner cash distributions during the years ended December 31, 2014 and 2013 include $21,947 and $100,277, respectively, related to equity cash distributions for Investor Partner units that have been repurchased by PDC. For additional disclosure regarding the allocation of cash distributions, refer to Note 8, Partners’ Equity and Cash Distributions.
v2.4.1.9
Divestitures and Discontinued Operations Divestitures and Discontiuned Operations (Tables)
12 Months Ended
Dec. 31, 2014
Discontinued Operations and Disposal Groups [Abstract]  
Schedule of Distribution of Proceeds from Asset Divestiture [Table Text Block]
In July 2013, this Partnership distributed proceeds received for the Piceance Basin asset divestiture to the Managing General Partner and Investor Partners as follows:
 
 
Amount
Distributed to:
 
(millions)
 
 
 
Managing General Partner
 
$
5.0

Investor Partners
 
8.5

Total
 
$
13.5

 
 
 
Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures [Table Text Block]
The following table presents statement of operations data related to this Partnership's discontinued operations for the Piceance Basin divestiture:
 
 
Year Ended
Statement of Operations - Discontinued Operations
 
December 31, 2013
 
 
 
Revenues:
 
 
Crude oil, natural gas and NGLs sales
 
$
1,771,961

 
 
 
Operating costs and expenses:
 
 
Crude oil, natural gas and NGLs production costs
 
744,569

Direct costs - general and administrative expense
 
326,051

Depreciation, depletion and amortization
 
155,210

Accretion of asset retirement obligations
 
6,878

Loss on sale of crude oil and natural gas properties
 
495,574

Total operating costs and expenses
 
1,728,282

 
 
 
Income from discontinued operations
 
$
43,679

 
 
 
v2.4.1.9
Supplemental Crude Oil, Natural Gas and NGL Information - Unaudited Supplemental Crude Oil, Natural Gas and NGL Information - Unaudited (Tables)
12 Months Ended
Dec. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]  
Schedule of Prices Used to Estimate Crude Oil and Natural Gas Reserves [Table Text Block]
The following table presents the prices used to estimate this Partnership's reserves, by commodity:

 
 
Price Used to Estimate Reserves (1)
As of December 31,
 
Crude Oil (per Bbl)
 
Natural Gas (per Mcf)
 
NGLs (per Bbl)
2014
 
$
84.33

 
$
3.92

 
$
25.53

2013
 
81.91

 
3.38

 
23.14



(1)
The prices used to estimate reserves have been prepared in accordance with the SEC. Future estimated cash flows were based on a 12-month average price calculated as the unweighted arithmetic average of the prices on the first day of each month, January through December, applied to this Partnership's year-end estimated proved reserves. Prices for each of the two years were adjusted for Btu content, transportation and regional price differences
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block]
The following table presents the changes in estimated quantities of this Partnership's reserves, all of which are located within the United States:
 
Natural Gas
 
NGLs
 
Crude Oil and Condensate
 
Crude Oil Equivalent
 
(MMcf)
 
(MBbl)
 
(MBbl)
 
(MBoe)
Proved Reserves:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proved reserves, January 1, 2013 (1)
13,036

 
595

 
853

 
3,621

Revisions of previous estimates and reclassifications
(712
)
 
(74
)
 
(117
)
 
(310
)
Dispositions (1)
(6,874
)
 

 
(15
)
 
(1,161
)
Production
(734
)
 
(22
)
 
(53
)
 
(197
)
Proved reserves, December 31, 2013
4,716

 
499

 
668

 
1,953

 
 
 
 
 
 
 
 
Revisions of previous estimates and reclassifications
(1,285
)
 
(100
)
 
(180
)
 
(494
)
Production
(132
)
 
(17
)
 
(33
)
 
(72
)
Proved reserves, December 31, 2014
3,299

 
382

 
455

 
1,387

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proved Developed Reserves, as of:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2013
4,716

 
499

 
668

 
1,953

December 31, 2014
3,299

 
382

 
455

 
1,387

 
 
 
 
 
 
 
 

(1)
Includes estimated reserve data related to this Partnership's Piceance Basin assets. In June 2013, this Partnership's Piceance Basin crude oil and natural gas properties were divested. See Note 11, Divestiture and Discontinued Operations, for additional information regarding this divestiture. As of January 1, 2013, total proved reserves related to this Partnership's Piceance Basin assets include 7,390 MMcf of natural gas and 17 MBbl of crude oil, for an aggregate of 1,249 MBoe of crude oil equivalent.
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]
Aggregate capitalized costs related to crude oil and natural gas development and production activities with applicable accumulated DD&A are presented below:
 
 As of December 31,
 
2014
 
2013
Leasehold costs
$
509,093

 
$
1,965,081

Development costs (1)
15,152,180

 
53,783,668

Crude oil and natural gas properties, successful efforts method, at cost
15,661,273

 
55,748,749

Less: Accumulated DD&A
(8,836,596
)
 
(31,819,541
)
Crude oil and natural gas properties, net
$
6,824,677

 
$
23,929,208



(1)
Includes estimated costs associated with this Partnership's asset retirement obligations. See Note 6, Asset Retirement Obligations, for further information.
v2.4.1.9
General and Basis of Presentation General and Basis of Presentation (Details) (USD $)
12 Months Ended
Dec. 31, 2014
Rate
Number_of_Limited_Partners
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
Number of Limited Partners 1,777pdce_NumberOfLimitedPartners
Managing General Partner, Ownership Interest Before Unit Repurchases 37.00%pdce_ManagingMemberOrGeneralPartnerOwnershipInterestBeforeUnitRepurchases
Investor Partner Ownership Interest 63.00%us-gaap_LimitedLiabilityCompanyLLCOrLimitedPartnershipLPMembersOrLimitedPartnersOwnershipInterest
Limited Partner Units Repurchased by Managing General Partner 73.0pdce_LimitedPartnerUnitsRepurchasedByManagingGeneralPartner
Average Price Paid for Units Repurchased by Managing General Partner $ 3,961pdce_AveragePricePaidForUnitsRepurchasedByManagingGeneralPartner
Managing General Partner Ownership Interest 38.00%us-gaap_LimitedLiabilityCompanyLLCOrLimitedPartnershipLPManagingMemberOrGeneralPartnerOwnershipInterest
v2.4.1.9
Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Details) (USD $)
Dec. 31, 2014
Cash and Cash Equivalents [Line Items]  
Cash, FDIC Insured Amount $ 250,000us-gaap_CashFDICInsuredAmount
v2.4.1.9
Derivative Financial Instruments Derivative Financial Instruments (Details) (Commodity Price Risk Management, net [Member], USD $)
12 Months Ended
Dec. 31, 2013
Commodity Price Risk Management, net [Member]
 
Derivative [Line Items]  
Net settlements $ 1,275,544us-gaap_DerivativeCashReceivedOnHedge
/ us-gaap_IncomeStatementLocationAxis
= pdce_CommodityPriceRiskManagementNetMember
Net change in fair value of unsettled derivatives (1,693,233)us-gaap_UnrealizedGainLossOnDerivatives
/ us-gaap_IncomeStatementLocationAxis
= pdce_CommodityPriceRiskManagementNetMember
Total commodity price risk management loss, net $ (417,689)us-gaap_DerivativeInstrumentsNotDesignatedAsHedgingInstrumentsGainLossNet
/ us-gaap_IncomeStatementLocationAxis
= pdce_CommodityPriceRiskManagementNetMember
v2.4.1.9
Concentration of Risk Concentration of Risk (Details)
12 Months Ended
Dec. 31, 2014
Rate
Dec. 31, 2013
Rate
Suncor Energy Marketing, Inc.    
Concentration Risk - Revenue    
Major Accounts Receivable Customer Percentage 15.00%pdce_MajorAccountsReceivableCustomerPercentage
/ us-gaap_ConcentrationRiskByTypeAxis
= pdce_SuncorEnergyMarketingIncMember
 
Percentage of Partnership Revenue 53.00%us-gaap_ConcentrationRiskPercentage1
/ us-gaap_ConcentrationRiskByTypeAxis
= pdce_SuncorEnergyMarketingIncMember
82.00%us-gaap_ConcentrationRiskPercentage1
/ us-gaap_ConcentrationRiskByTypeAxis
= pdce_SuncorEnergyMarketingIncMember
DCP Midstream, LP [Member]    
Concentration Risk - Revenue    
Major Accounts Receivable Customer Percentage 27.00%pdce_MajorAccountsReceivableCustomerPercentage
/ us-gaap_ConcentrationRiskByTypeAxis
= pdce_DcpMidstreamLpMember
 
Percentage of Partnership Revenue 24.00%us-gaap_ConcentrationRiskPercentage1
/ us-gaap_ConcentrationRiskByTypeAxis
= pdce_DcpMidstreamLpMember
18.00%us-gaap_ConcentrationRiskPercentage1
/ us-gaap_ConcentrationRiskByTypeAxis
= pdce_DcpMidstreamLpMember
Concord Energy [Member]    
Concentration Risk - Revenue    
Major Accounts Receivable Customer Percentage 58.00%pdce_MajorAccountsReceivableCustomerPercentage
/ us-gaap_ConcentrationRiskByTypeAxis
= pdce_ConcordEnergyMember
 
Percentage of Partnership Revenue 23.00%us-gaap_ConcentrationRiskPercentage1
/ us-gaap_ConcentrationRiskByTypeAxis
= pdce_ConcordEnergyMember
0.00%us-gaap_ConcentrationRiskPercentage1
/ us-gaap_ConcentrationRiskByTypeAxis
= pdce_ConcordEnergyMember
v2.4.1.9
Asset Retirement Obligations Asset Retirement Obligations (Details) (USD $)
12 Months Ended
Dec. 31, 2014
Dec. 31, 2013
Changes in Carrying Amounts of the Asset Retirement Obligation    
Balance at beginning of year