v2.4.0.8
Document Entity Information Document (USD $)
12 Months Ended
Dec. 31, 2013
Feb. 28, 2014
Jun. 30, 2013
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, 2013    
Document Fiscal Year Focus 2013    
Document Fiscal Period Focus FY    
Amendment Flag false    
Entity Common Stock, Shares Outstanding   0.00  
Additional General Partnership Units Outstanding   0.00  
Entity Well-Known Seasoned Issuer No    
Entity Voluntary Filers No    
Entity Current Reporting Status Yes    
Entity Public Float     $ 0
v2.4.0.8
Balance Sheets Statement (USD $)
Dec. 31, 2013
Dec. 31, 2012
Current assets:    
Cash and cash equivalents $ 570,376 $ 570,376
Accounts receivable 378,940 865,944
Crude oil inventory 55,308 42,939
Due from Managing General Partner-derivatives 0 4,409,574
Due from Managing General Partner-other, net 0 800,598
Total current assets 1,004,624 6,689,431
Crude oil and natural gas properties, successful efforts method, at cost 55,748,749 79,601,649
Less: Accumulated depreciation, depletion and amortization (31,819,541) (38,868,788)
Crude oil and natural gas properties, net 23,929,208 40,732,861
Other assets 89,630 46,711
Total Assets 25,023,462 47,469,003
Current liabilities:    
Accounts payable and accrued expenses 33,041 90,570
Due to Managing General Partner-derivatives 0 2,004,594
Due to Managing General Partner-other, net 119,994 0
Total current liabilities 153,035 2,095,164
Asset retirement obligations 935,813 1,110,093
Total liabilities 1,088,848 3,205,257
Commitments and contingent liabilities      
Partners' equity:    
Managing General Partner 3,661,859 11,183,638
Limited Partners - 4470 units issued and outstanding 20,272,755 33,080,108
Total Partners' equity 23,934,614 44,263,746
Total Liabilities and Partners' Equity $ 25,023,462 $ 47,469,003
v2.4.0.8
Balance Sheet Parentheticals (Parentheticals)
Dec. 31, 2013
Dec. 31, 2012
Balance Sheet Parentheticals [Abstract]    
Limited Partners' Capital Account, Units Issued 4,470.00 4,470.00
Limited Partners' Capital Account, Units Outstanding 4,470.00 4,470.00
v2.4.0.8
Statements of Operations Statement (USD $)
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Revenues:    
Crude oil, natural gas and NGLs sales $ 5,702,943 $ 5,904,716
Commodity price risk management gain (loss), net (417,689) 1,078,580
Total revenues 5,285,254 6,983,296
Operating costs and expenses:    
Crude oil, natural gas and NGLs production costs 1,395,391 1,304,676
Direct costs - general and administrative 209,500 200,972
Depreciation, depletion and amortization 3,121,340 3,466,521
Accretion of asset retirement obligations 68,266 63,165
Total operating costs and expenses 4,794,497 5,035,334
Income from continuing operations 490,757 1,947,962
Income (loss) from discontinued operations 43,679 (3,327,789)
Net income (loss) 534,436 (1,379,827)
Income from continuing operations 490,757 1,947,962
Less: Managing General Partner interest in net income 181,580 720,746
Net income allocated to Investor Partners 309,177 1,227,216
Net loss per Investor Partner unit, Continuing operations $ 69 $ 275
Net loss per Investor Partner unit, Discontinued operations $ 6 $ (469)
Net loss per Investor Partner unit $ 75 $ (194)
Investor Partner units outstanding 4,470.00 4,470.00
Managing General Partner
   
Operating costs and expenses:    
Income (loss) from discontinued operations 16,161 (1,231,282)
Limited Partner [Member]
   
Operating costs and expenses:    
Income (loss) from discontinued operations $ 27,518 $ (2,096,507)
v2.4.0.8
Statement of Partners' Equity Statement (USD $)
Total
Investor Partners
Managing General Partner
Balance at Dec. 31, 2011 $ 52,780,496 $ 38,445,661 $ 14,334,835
Change in Partners' Equity:      
Distributions to Partners (7,136,923) (4,496,262) (2,640,661)
Net income (1,379,827) (869,291) (510,536)
Balance at Dec. 31, 2012 44,263,746 33,080,108 11,183,638
Change in Partners' Equity:      
Distributions to Partners (20,863,568) (13,144,048) (7,719,520)
Net income 534,436 336,695 197,741
Balance at Dec. 31, 2013 $ 23,934,614 $ 20,272,755 $ 3,661,859
v2.4.0.8
Statements of Cash Flows Statement (USD $)
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Cash flows from operating activities:    
Net income (loss) $ 534,436 $ (1,379,827)
Adjustments to net income (loss) to reconcile to net cash from operating activities:    
Depreciation, depletion and amortization 3,276,550 5,439,026
Accretion of asset retirement obligations 75,144 78,907
Net change in fair value of unsettled derivatives 1,693,233 2,384,355
Loss on sale of crude oil and natural gas properties 495,574 0
Impairment of crude oil and natural gas properties 0 2,191,002
Changes in assets and liabilities:    
Accounts receivable 487,004 (97,994)
Crude oil inventory (17,283) 4,308
Other assets (42,919) (46,711)
Accounts payable and accrued expenses (57,529) (4,959)
Due to Managing General Partner-other, net 130,241 0
Due from Managing General Partner-other, net 800,598 (389,027)
Net cash from operating activities 7,375,049 8,179,080
Cash flows from investing activities:    
Capital expenditures for crude oil and natural gas properties 0 (3,162,158)
Proceeds from sale of crude oil and natural gas properties 13,488,519 0
Net cash from investing activities 13,488,519 (3,162,158)
Cash flows from financing activities:    
Distributions to Partners (20,863,568) (7,136,923)
Net cash from financing activities (20,863,568) (7,136,923)
Net change in cash and cash equivalents 0 (2,120,001)
Cash and cash equivalents, beginning of period 570,376 2,690,377
Cash and cash equivalents, end of period $ 570,376 $ 570,376
v2.4.0.8
General and Basis of Presentation
12 Months Ended
Dec. 31, 2013
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, 2013, there were 1,783 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, 2013, the Managing General Partner had repurchased 41.3 units of Partnership interests from the Investor Partners at an average price of $4,269 per unit. As of December 31, 2013, the Managing General Partner owned 37.6% of this Partnership.

Certain reclassifications have been made to prior period financial statements to conform to the current year presentation. These reclassifications had no impact on previously reported cash flows, net income, earnings per investor partner unit or partners' equity.
v2.4.0.8
Summary of Significant Accounting Policies
12 Months Ended
Dec. 31, 2013
Accounting Policies [Abstract]  
Significant Accounting Policies [Text Block]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Management's Estimates

The preparation of this Partnership's financial statements in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) requires this Partnership 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 the financial statements include estimates of natural gas, NGLs and crude oil sales revenue, proved reserves, future cash flows from crude oil, natural gas and NGLs properties and valuation of derivative instruments.

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. No allowance for doubtful accounts was deemed necessary at December 31, 2013 or 2012.

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. 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.

All derivative assets and liabilities were 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 captioned, “Commodity price risk management gain, 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, 2013, this Partnership had no outstanding derivative instruments.

The validation of the derivative instrument's fair value was performed by the Managing General Partner. While the Managing General Partner used common industry practices to develop this Partnership's valuation techniques, changes in this Partnership's pricing methodologies or the underlying assumptions could have resulted in significantly different fair values. See Note 3, Fair Value of Financial Instruments, and Note 4, Derivative Financial Instruments, for a discussion of this Partnership's derivative fair value measurements as of December 31, 2012.

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 sheet.

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 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 Adopted Accounting Standard. On January 1, 2013, this Partnership adopted changes issued by the Financial Accounting Standards Board regarding the disclosure of offsetting assets and liabilities. These changes require an entity to disclose both gross and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an enforceable master netting arrangement or similar agreement. The enhanced disclosures enable users of an entity’s financial statements to understand and evaluate the effect or potential effect of master netting arrangements on the entity’s financial position, including the effect or potential effect of rights of setoff associated with certain financial instruments and derivative instruments. Adoption of these changes had no impact on the financial statements.
v2.4.0.8
Fair Value of Financial Instruments
12 Months Ended
Dec. 31, 2013
Fair Value Disclosures [Abstract]  
Fair Value Disclosures [Text Block]
FAIR VALUE OF FINANCIAL INSTRUMENTS

Derivative Financial Instruments

Determination of fair value. This Partnership's fair value measurements are 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. The three levels of inputs that may be used to measure fair value are defined as:

Level 1 - Quoted prices (unadjusted) for identical assets or liabilities in active markets.

Level 2 - Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means.

Level 3 - Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity.

Derivative instruments that were due to mature subsequent to June 30, 2013 were either liquidated or sold to Caerus during the quarter ended June 30, 2013. See Note 11, Divestitures and Discontinued Operations, for additional information regarding transactions with Caerus. Accordingly, as of December 31, 2013, this Partnership did not have any derivative instruments in place for its future production. When applicable, the Managing General Partner measured the fair value of this Partnership's derivative instruments based on a pricing model that utilized market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, natural gas forward curve, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of the Managing General Partner's credit standing on the fair value of derivative liabilities and the effect of the Managing General Partner's counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position.

The Managing General Partner validated its fair value measurement through the review of counterparty statements and other supporting documentation, the determination that the source of the inputs is valid, the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and assumptions. While the Managing General Partner used common industry practices to develop its valuation techniques, and believed this Partnership's valuation method was appropriate and consistent with those used by other market participants, changes in the Managing General Partner's pricing methodologies or the underlying assumptions could have resulted in significantly different fair values.

 
This Partnership's fixed-price swaps and basis swaps as of December 31, 2012 were included in Level 2. The following table presents this Partnership's derivative assets and liabilities that had been measured at fair value on a recurring basis:
 
Balance Sheet
 
December 31, 2012
 
Line Item
 
 Level 2
 
 
 
 
 
 
Assets:
 
 
 
 
Current
 
 
 
 
Commodity-based derivatives
Due from Managing General Partner-derivatives
 
$
4,409,574

 
 Total assets
 
 
4,409,574

 
 
 
 
 
 
Liabilities:
 
 
 
 
Current
 
 
 
 
Basis protection derivative contracts
Due to Managing General Partner-derivatives
 
2,004,594

 
 Total liabilities
 
 
2,004,594

 
 Net asset
 
 
$
2,404,980

 


Non-Derivative Financial Assets and Liabilities

The carrying value of the financial instruments included in current assets and current liabilities approximate fair value due to the short-term maturities of these instruments.

See Note 2, Summary of Significant Accounting Policies, Crude Oil and Natural Gas Properties and Asset Retirement Obligations, for a discussion of how this Partnership determined fair value for these assets and liabilities.
v2.4.0.8
Derivative Financial Instruments
12 Months Ended
Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Derivative Instruments Disclosure [Text Block]
DERIVATIVE FINANCIAL INSTRUMENTS

This Partnership's results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas and NGLs. Prior to June 30, 2013, to manage a portion of this Partnership's exposure to price volatility from producing crude oil and natural gas, the Managing General Partner utilized an economic hedging strategy for this Partnership's crude oil and natural gas sales in which PDC, as Managing General Partner, entered into derivative contracts on behalf of this Partnership to protect against price declines in future periods. While the Managing General Partner structured these derivatives to reduce this Partnership's exposure to changes in price associated with the derivative commodities, they also limited the benefit this Partnership might otherwise have received from price increases in the physical market. Partnership policy prohibited the use of crude oil and natural gas derivative instruments for speculative purposes. In June 2013, derivative instruments that were due to mature subsequent to June 30, 2013 were liquidated or sold to Caerus. Accordingly, as of December 31, 2013, this Partnership did not have any derivative instruments in place for its future production. Currently, the Managing General Partner does not anticipate entering into derivative instruments for any of this Partnership's future production.

The following tables present the impact of this Partnership's derivative instruments on this Partnership's accompanying statements of operations:
 
 
Year ended December 31,
Statement of operations line item:
 
2013
 
 
2012
Commodity price risk management gain (loss), net
 
 
 
 
 
Net settlements
 
$
1,275,544

 
 
$
3,462,935

Net change in fair value of unsettled derivatives
 
(1,693,233
)
 
 
(2,384,355
)
Total commodity price risk management gain (loss), net
$
(417,689
)
 
 
$
1,078,580

v2.4.0.8
Concentration of Risk
12 Months Ended
Dec. 31, 2013
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, 2013 and 2012, this Partnership did not record an allowance for doubtful accounts. 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. This Partnership did not incur any losses on accounts receivable for the years ended December 31, 2013 and 2012. As of December 31, 2013, this Partnership had two customers representing 10% or more of the accounts receivable balance: Suncor Energy Marketing, Inc. and DCP Midstream, LP represented 76% and 22%, 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
 
2013
 
2012
Suncor Energy Marketing, Inc.
 
82%
 
84%
DCP Midstream, LP
 
18%
 
16%
v2.4.0.8
Asset Retirement Obligations
12 Months Ended
Dec. 31, 2013
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,
 
2013
 
2012
 
 
 
 
Balance at beginning of period
$
1,110,093

 
$
1,031,186

Obligations discharged with divestiture of properties(1)
(249,424
)
 

Accretion expense
75,144

 
78,907

Balance at end of period
$
935,813

 
$
1,110,093



(1)
This Partnership's asset retirement obligations relative 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.
v2.4.0.8
Commitments and Contingencies
12 Months Ended
Dec. 31, 2013
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. Liabilities for environmental remediation efforts are included in line item captioned “Accounts payable and accrued expenses” on the balance sheets.

During the year ended December 31, 2013, 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, 2013. This Partnership's environmental remediation liabilities were approximately $5,000 as of December 31, 2012.

The Managing General Partner is not currently aware of any environmental claims existing as of December 31, 2013 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.

Royalty Matters

During the year ended December 31, 2013, this Partnership recognized charges totaling approximately $326,000 related to royalty payment disputes with interest owners in the Piceance Basin. These charges were included in Direct costs - general and administrative expenses within discontinued operations. The settlement charges were allocated to this Partnership based upon historical revenue amounts and were paid during 2013, thereby settling all current and future obligations related to this matter.
v2.4.0.8
Partners' Equity and Cash Distributions
12 Months Ended
Dec. 31, 2013
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 twelve 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. The Managing General Partner determines and distributes cash on a monthly basis, if funds are 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,
 
 
2013
 
2012
 
 
 
 
 
Cash distributions
 
$
20,863,568

 
$
7,136,923



Cash distributions increased in 2013 compared to 2012, 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.
v2.4.0.8
Transactions with Managing General Partner
12 Months Ended
Dec. 31, 2013
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 fair value of this Partnership's portion of open derivative instruments were recorded on the December 31, 2012 balance sheet under the captions “Due from Managing General Partner-derivatives” in the case of a positive fair value of unsettled derivatives and “Due to Managing General Partner-derivatives” in the case of a negative fair value of unsettled derivatives. As of December 31, 2013, this Partnership had no outstanding derivative instruments.

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

    
 
December 31, 2013
 
December 31, 2012
Crude oil, natural gas and NGLs sales revenues
collected from this Partnership's third-party customers
$
306,014

 
$
871,548

Net settlements of derivatives

 
356,531

Other (1)
(426,008
)
 
(427,481
)
Total Due (to) from Managing General Partner-other, net
$
(119,994
)
 
$
800,598


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

Commencing with March 2012 well operations, the Managing General Partner withholds from monthly Partnership cash available for distributions amounts to be used to fund statutorily-mandated well plugging, abandonment and environmental site restoration expenditures. A Partnership well may be sold or plugged, reclaimed and abandoned, with consent of all non-operators, when depleted or an evaluation is made that the well has become uneconomical to produce. Per-well plugging fees withheld during 2013 and 2012 were $50 per well each month the well produced. The total amount withheld from Partnership's cash available for distributions for the purposes of funding future Partnership obligations is recorded on the balance sheets in the long-term asset line captioned "Other assets." PDC plans to discontinue withholding these funds in early 2014 and will refund all funds withheld to the Partnership.

The following table presents Partnership transactions, excluding derivative transactions which are more fully detailed in Note 4, Derivative Financial Instruments, with the Managing General Partner for the years ended December 31, 2013 and 2012. “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,
 
2013
 
2012
 Well operations and maintenance (1)
$
1,660,093

 
$
2,260,438

 Gathering, compression and processing fees (2)
119,017

 
339,542

 Direct costs - general and administrative (3)
535,551

 
200,972

 Refracturing and recompletion costs (4)

 
3,159,943

 Cash distributions (5)
7,819,797

 
2,658,297


(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) Refracturing and recompletion costs relate to expenditures recorded pursuant to the Additional Development Plan.
(5) 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, 2013 and 2012 include $100,277 and $17,636, respectively, related to equity cash distributions for Investor Partner units repurchased by PDC. For additional disclosure regarding the allocation of cash distributions, refer to Note 8, Partners’ Equity and Cash Distributions.
v2.4.0.8
Impairment of Capitalized Costs
12 Months Ended
Dec. 31, 2013
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 2012, this Partnership recognized an impairment charge of approximately $2.2 million associated with its Piceance Basin proved oil and natural gas properties. The assets were determined to be impaired as the estimated undiscounted future net cash flows were less than the carrying value of the assets. The fair value for determining the amount of the impairment charge was based on estimated future cash flows from unrelated third-party bids, a Level 3 input. 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.
v2.4.0.8
Divestitures and Discontinued Operations Divestitures and Discontinued Operations (Notes)
12 Months Ended
Dec. 31, 2013
Discontinued Operations and Disposal Groups [Abstract]  
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]

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 Caerus 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 December 31,
Statement of Operations - Discontinued Operations
 
2013
 
2012
 
 
 
 
 
Revenues:
 
 
 
 
Crude oil, natural gas and NGLs sales
 
$
1,771,961

 
$
2,356,542

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

 
1,505,082

Direct costs - general and administrative expense
 
326,051

 

Depreciation, depletion and amortization
 
155,210

 
1,972,505

Accretion of asset retirement obligations
 
6,878

 
15,742

Impairment of crude oil and natural gas properties
 

 
2,191,002

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

 

Total operating costs and expenses
 
1,728,282

 
5,684,331

 
 
 
 
 
Income (loss) from discontinued operations
 
$
43,679

 
$
(3,327,789
)
 
 
 
 
 


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.
v2.4.0.8
Supplemental Crude Oil, Natural Gas and NGL Information - Unaudited
12 Months Ended
Dec. 31, 2013
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 2013 and 2012 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, 2013 and 2012, 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 ten years after initial well drilling. Funds of $3.1 million, which were provided by the withholding of distributable cash flows from the Managing General Partner and Investor Partners, were utilized for payment of additional development activities during 2012. 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)
2013
 
$
81.91

 
$
3.38

 
$
23.14

2012
 
87.51

 
2.31

 
23.07



(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 by field for Btu content, transportation and regional price differences; however, they were not adjusted to reflect the value of this Partnership's commodity derivatives.

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, 2012
18,415

 
697

 
879

 
4,645

Revisions of previous estimates and reclassifications
(3,926
)
 
(81
)
 
34

 
(701
)
Production
(1,453
)
 
(21
)
 
(60
)
 
(323
)
Proved reserves, December 31, 2012 (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

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proved Developed Reserves, as of:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2012
13,036

 
595

 
853

 
3,621

December 31, 2013
4,716

 
499

 
668

 
1,953

 
 
 
 
 
 
 
 

(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 December 31, 2012, 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.

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.

2012 Activity. As of December 31, 2012, this Partnership recorded a downward revision of its previous estimate of proved reserves by approximately 701 MBoe. The revision includes downward revisions to previous estimates of 3,926 MMcf of natural gas and 81 MBbls of NGLs, partially offset by an upward revision of 34 MBbls of crude oil. The downward revisions were the result of lower pricing and reduced asset performance. Proved undeveloped reserves of 268 MBoe were transferred to proved developed reserves in 2012 due to the reclassification of the Partnership's estimated Wattenberg behind pipe reserves as a result of the Managing General Partner's determination of the cost of a recompletion becoming less significant as compared to the cost of drilling a new well. There were no proved undeveloped reserves developed in 2012. There were no proved undeveloped reserves attributable to this Partnership's assets as of December 31, 2012.
  
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,
 
2013
 
2012 (1)
Leasehold costs
$
1,965,081

 
$
2,016,120

Development costs (2)
53,783,668

 
77,585,529

Crude oil and natural gas properties, successful efforts method, at cost
55,748,749

 
79,601,649

Less: Accumulated DD&A
(31,819,541
)
 
(38,868,788
)
Crude oil and natural gas properties, net
$
23,929,208

 
$
40,732,861



(1) Includes Piceance Basin crude oil and natural gas properties of $23,843,000, and related accumulated DD&A of $10,171,000, divested in 2013. See Note 11, Divestiture and Discontinued Operations, for further information.
(2) Includes estimated costs associated with this Partnership's asset retirement obligations. See Note 6, Asset Retirement Obligations, for further information.

This Partnership, from time-to-time, invests in additional equipment which supports treatment, delivery and measurement of crude oil and natural gas or environmental protection. This Partnership also invests in equipment and services to complete refracturing or recompletion opportunities pursuant to the Additional Development Plan. There were no investments for this Partnership in 2013. Substantially all of the $3.2 million investment in 2012 is attributable to activities pursuant to the Additional Development Plan.

This Partnership recorded an impairment charge of $2,191,002 for the year ended December 31, 2012 associated with its Piceance Basin proved oil and natural gas properties. Accordingly, this Partnership reduced crude oil and natural gas properties by $3,820,877 and related accumulated depreciation, depletion and amortization for those properties by $1,629,875 as of December 31, 2012. See Note 10, Impairment of Capitalized Costs, for additional disclosure related to this Partnership's proved property impairment.
v2.4.0.8
Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Policies)
12 Months Ended
Dec. 31, 2013
Accounting Policies [Abstract]  
Use of Estimates, Policy [Policy Text Block]
The preparation of this Partnership's financial statements in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) requires this Partnership 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 the financial statements include estimates of natural gas, NGLs and crude oil sales revenue, proved reserves, future cash flows from crude oil, natural gas and NGLs properties and valuation of derivative instruments
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
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 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 captioned, “Commodity price risk management gain, 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, 2013, this Partnership had no outstanding derivative instruments.

The validation of the derivative instrument's fair value was performed by the Managing General Partner. While the Managing General Partner used common industry practices to develop this Partnership's valuation techniques, changes in this Partnership's pricing methodologies or the underlying assumptions could have resulted in significantly different fair values
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. 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 sheet.
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 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]
Recent Accounting Standards

Recently Adopted Accounting Standard. On January 1, 2013, this Partnership adopted changes issued by the Financial Accounting Standards Board regarding the disclosure of offsetting assets and liabilities. These changes require an entity to disclose both gross and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an enforceable master netting arrangement or similar agreement. The enhanced disclosures enable users of an entity’s financial statements to understand and evaluate the effect or potential effect of master netting arrangements on the entity’s financial position, including the effect or potential effect of rights of setoff associated with certain financial instruments and derivative instruments. Adoption of these changes had no impact on the financial statements.
v2.4.0.8
Fair Value of Financial Instruments Fair Value Measurements and Disclosures (Tables)
12 Months Ended
Dec. 31, 2013
Fair Value Disclosures [Abstract]  
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]
The following table presents this Partnership's derivative assets and liabilities that had been measured at fair value on a recurring basis:
 
Balance Sheet
 
December 31, 2012
 
Line Item
 
 Level 2
 
 
 
 
 
 
Assets:
 
 
 
 
Current
 
 
 
 
Commodity-based derivatives
Due from Managing General Partner-derivatives
 
$
4,409,574

 
 Total assets
 
 
4,409,574

 
 
 
 
 
 
Liabilities:
 
 
 
 
Current
 
 
 
 
Basis protection derivative contracts
Due to Managing General Partner-derivatives
 
2,004,594

 
 Total liabilities
 
 
2,004,594

 
 Net asset
 
 
$
2,404,980

 
v2.4.0.8
Derivative Financial Instruments Derivative Financial Instruments (Tables)
12 Months Ended
Dec. 31, 2013
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 December 31,
Statement of operations line item:
 
2013
 
 
2012
Commodity price risk management gain (loss), net
 
 
 
 
 
Net settlements
 
$
1,275,544

 
 
$
3,462,935

Net change in fair value of unsettled derivatives
 
(1,693,233
)
 
 
(2,384,355
)
Total commodity price risk management gain (loss), net
$
(417,689
)
 
 
$
1,078,580

v2.4.0.8
Concentration of Risk Concentration of Risk (Tables)
12 Months Ended
Dec. 31, 2013
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
 
2013
 
2012
Suncor Energy Marketing, Inc.
 
82%
 
84%
DCP Midstream, LP
 
18%
 
16%
v2.4.0.8
Asset Retirement Obligations Asset Retirement Obligations (Tables)
12 Months Ended
Dec. 31, 2013
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,
 
2013
 
2012
 
 
 
 
Balance at beginning of period
$
1,110,093

 
$
1,031,186

Obligations discharged with divestiture of properties(1)
(249,424
)
 

Accretion expense
75,144

 
78,907

Balance at end of period
$
935,813

 
$
1,110,093



(1)
This Partnership's asset retirement obligations relative 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.
v2.4.0.8
Partners' Equity and Cash Distributions (Tables)
12 Months Ended
Dec. 31, 2013
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.
v2.4.0.8
Partners' Equity and Cash Distributions Cash Distributions (Tables)
12 Months Ended
Dec. 31, 2013
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,
 
 
2013
 
2012
 
 
 
 
 
Cash distributions
 
$
20,863,568

 
$
7,136,923

v2.4.0.8
Transactions with Managing General Partner Transactions with Managing General Partner (Tables)
12 Months Ended
Dec. 31, 2013
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) from Managing General Partner-other, net” which remain undistributed or unsettled with this Partnership's investors as of the dates indicated:

    
 
December 31, 2013
 
December 31, 2012
Crude oil, natural gas and NGLs sales revenues
collected from this Partnership's third-party customers
$
306,014

 
$
871,548

Net settlements of derivatives

 
356,531

Other (1)
(426,008
)
 
(427,481
)
Total Due (to) from Managing General Partner-other, net
$
(119,994
)
 
$
800,598


(1)
All other unsettled transactions, excluding derivative instruments, between this Partnership and the Managing General Partner. The majority of these 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, excluding derivative transactions which are more fully detailed in Note 4, Derivative Financial Instruments, with the Managing General Partner for the years ended December 31, 2013 and 2012. “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,
 
2013
 
2012
 Well operations and maintenance (1)
$
1,660,093

 
$
2,260,438

 Gathering, compression and processing fees (2)
119,017

 
339,542

 Direct costs - general and administrative (3)
535,551

 
200,972

 Refracturing and recompletion costs (4)

 
3,159,943

 Cash distributions (5)
7,819,797

 
2,658,297


(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) Refracturing and recompletion costs relate to expenditures recorded pursuant to the Additional Development Plan.
(5) 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, 2013 and 2012 include $100,277 and $17,636, respectively, related to equity cash distributions for Investor Partner units repurchased by PDC. For additional disclosure regarding the allocation of cash distributions, refer to Note 8, Partners’ Equity and Cash Distributions.
v2.4.0.8
Divestitures and Discontinued Operations Divestitures and Discontiuned Operations (Tables)
12 Months Ended
Dec. 31, 2013
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 December 31,
Statement of Operations - Discontinued Operations
 
2013
 
2012
 
 
 
 
 
Revenues:
 
 
 
 
Crude oil, natural gas and NGLs sales
 
$
1,771,961

 
$
2,356,542

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

 
1,505,082

Direct costs - general and administrative expense
 
326,051

 

Depreciation, depletion and amortization
 
155,210

 
1,972,505

Accretion of asset retirement obligations
 
6,878

 
15,742

Impairment of crude oil and natural gas properties
 

 
2,191,002

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

 

Total operating costs and expenses
 
1,728,282

 
5,684,331

 
 
 
 
 
Income (loss) from discontinued operations
 
$
43,679

 
$
(3,327,789
)
 
 
 
 
 
v2.4.0.8
Supplemental Crude Oil, Natural Gas and NGL Information - Unaudited Supplemental Crude Oil, Natural Gas and NGL Information - Unaudited (Tables)
12 Months Ended
Dec. 31, 2013
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)
2013
 
$
81.91

 
$
3.38

 
$
23.14

2012
 
87.51

 
2.31

 
23.07



(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 by field for Btu content, transportation and regional price differences; however, they were not adjusted to reflect the value of this Partnership's commodity derivatives.
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, 2012
18,415

 
697

 
879

 
4,645

Revisions of previous estimates and reclassifications
(3,926
)
 
(81
)
 
34

 
(701
)
Production
(1,453
)
 
(21
)
 
(60
)
 
(323
)
Proved reserves, December 31, 2012 (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

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proved Developed Reserves, as of:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2012
13,036

 
595

 
853

 
3,621

December 31, 2013
4,716

 
499

 
668

 
1,953

 
 
 
 
 
 
 
 

(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 December 31, 2012, 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,
 
2013
 
2012 (1)
Leasehold costs
$
1,965,081

 
$
2,016,120

Development costs (2)
53,783,668

 
77,585,529

Crude oil and natural gas properties, successful efforts method, at cost
55,748,749

 
79,601,649

Less: Accumulated DD&A
(31,819,541
)
 
(38,868,788
)
Crude oil and natural gas properties, net
$
23,929,208

 
$
40,732,861



(1) Includes Piceance Basin crude oil and natural gas properties of $23,843,000, and related accumulated DD&A of $10,171,000, divested in 2013. See Note 11, Divestiture and Discontinued Operations, for further information.
(2) Includes estimated costs associated with this Partnership's asset retirement obligations. See Note 6, Asset Retirement Obligations, for further information.
v2.4.0.8
General and Basis of Presentation General and Basis of Presentation (Details) (USD $)