Rockies Region 2006 Limited Partnership 10-K28 Mar 172016 FY Annual reportFinancial data

Company Profile

Document Entity Information Doc

Document Entity Information Document - USD ($)	12 Months Ended
Document Entity Information Document - USD ($)	Dec. 31, 2016	Jun. 30, 2016	Mar. 15, 2016
Entity Information
Entity Registrant Name	Rockies Region 2006 Limited Partnership
Entity Central Index Key	1,376,912
Current Fiscal Year End Date	--12-31
Entity Filer Category	Smaller Reporting Company
Document Type	10-K
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding			0
Additional General Partnership Units Outstanding			0
Entity Well-Known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float		$ 0

Balance Sheets Statement

Balance Sheets Statement - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 11,215	$ 12,445
Accounts receivable	58,187	53,932
Crude oil inventory	59,362	57,846
Total current assets	128,764	124,223
Crude oil and natural gas properties, successful efforts method, at cost	1,895,810	1,521,446
Less: Accumulated depreciation, depletion and amortization	(779,728)	(571,528)
Crude oil and natural gas properties, net	1,116,082	949,918
Total Assets	1,244,846	1,074,141
Current liabilities:
Accounts payable and accrued expenses	5,588	4,326
Due to Managing General Partner-other, net	322,249	135,480
Current portion of asset retirement obligations	977,500	345,000
Total current liabilities	1,305,337	484,806
Asset retirement obligations	1,551,929	1,846,433
Total liabilities	2,857,266	2,331,239
Commitments and contingent liabilities
Partners' equity:
Managing General Partner	(5,532,608)	(5,401,139)
Limited Partners - 4,497.03 units issued and outstanding	3,920,188	4,144,041
Total Partners' equity	(1,612,420)	(1,257,098)
Total Liabilities and Partners' Equity	$ 1,244,846	$ 1,074,141

Balance Sheet Parentheticals (P

Balance Sheet Parentheticals (Parentheticals) - shares	Dec. 31, 2016	Dec. 31, 2015
Balance Sheet Parentheticals [Abstract]
Limited Partners' Capital Account, Units Issued	4,497.03	4,497.03
Limited Partners' Capital Account, Units Outstanding	4,497.03	4,497.03

Statements of Operations Statem

Statements of Operations Statement - USD ($)	12 Months Ended
Statements of Operations Statement - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Revenues:
Crude Oil, natural gas and NGLs sales	$ 825,271	$ 779,509
Operating costs and expenses:
Crude oil, natural gas and NGLs production costs	628,457	658,989
Direct costs - general and administrative	177,663	163,009
Depreciation, depletion and amortization	208,200	379,645
Accretion of asset retirement obligations	166,273	126,736
Impairment of crude oil and natural gas properties	0	4,611,188
Total operating costs and expenses	1,180,593	5,939,567
Net loss	(355,322)	(5,160,058)
Less: Managing General Partner interest in net loss from continuing operations	(131,469)	(1,909,221)
Net loss allocated to Investor Partners	$ (223,853)	$ (3,250,837)
Net loss per Investor Partner unit	$ (49.78)	$ (722.89)
Investor Partner units outstanding	4,497.03	4,497.03

Statement of Partners' Equity S

Statement of Partners' Equity Statement - USD ($)	Total	Investor Partners	Managing General Partner
Balance at Dec. 31, 2014	$ 3,950,127	$ 7,424,593	$ (3,474,466)
Change in Partners' Equity:
Distributions to Partners	(47,167)	(29,715)	(17,452)
Net loss	(5,160,058)	(3,250,837)	(1,909,221)
Balance at Dec. 31, 2015	(1,257,098)	4,144,041	(5,401,139)
Change in Partners' Equity:
Distributions to Partners	0	0	0
Net loss	(355,322)	(223,853)	(131,469)
Balance at Dec. 31, 2016	$ (1,612,420)	$ 3,920,188	$ (5,532,608)

Statements of Cash Flows Statem

Statements of Cash Flows Statement - USD ($)	12 Months Ended
Statements of Cash Flows Statement - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Cash flows from operating activities:
Net loss	$ (355,322)	$ (5,160,058)
Adjustments to net loss to reconcile to net cash from operating activities:
Depreciation, depletion and amortization	208,200	379,645
Accretion of asset retirement obligations	166,273	126,736
Impairment of crude oil and natural gas properties	0	4,611,188
Changes in assets and liabilities:
Accounts receivable	(4,255)	5,538
Crude oil inventory	(1,516)	(4,053)
Accounts payable and accrued expenses	1,262	(1,952)
Asset Retirement Obligations	(147,713)	0
Due to Managing General Partner-other, net	140,512	36,594
Net cash from operating activities	7,441	(6,362)
Cash flows from investing activities:
Capital expenditures for crude oil and natural gas properties	(8,671)	(70,252)
Net cash from investing activities	(8,671)	(70,252)
Cash flows from financing activities:
Distributions to Partners	0	(47,167)
Net cash from financing activities	0	(47,167)
Net change in cash and cash equivalents	(1,230)	(123,781)
Cash and cash equivalents, beginning of period	12,445	136,226
Cash and cash equivalents, end of period	11,215	12,445
Supplemental disclosure of non-cash activity:
Change in due to managing general partner-other, net related to purchases of properties and equipment	46,257	0
Change in asset retirement obligation, with corresponding change in crude oil and natural gas properties, net of disposal	$ 319,436	$ 390,715

General and Basis of Presentati

General and Basis of Presentation	12 Months Ended
General and Basis of Presentation	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]	GENERAL Rockies Region 2006 Limited Partnership was organized in 2006 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, 2016 , there were 1,975 Investor Partners in this Partnership. PDC is the designated Managing General Partner of this Partnership and owns a 37 percent 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 percent to the Investor Partners, which are shared pro rata based upon the number of units in this Partnership, and 37 percent 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. Since the formula for the repurchase price is set at a minimum of four times the most recent 12 months of cash distribution, due to the suspension of cash distributions in the first quarter of 2017, there is no value upon which to base the calculation. Through December 31, 2016 , the Managing General Partner had repurchased 163.8 units of Partnership interests from the Investor Partners at an average price of $2,351 per unit. As of December 31, 2016 , the Managing General Partner owned 39.3 percent 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, future cash flows from crude oil and natural gas properties and impairment of proved properties.

Going Concern (Notes)

Going Concern (Notes)	12 Months Ended
Going Concern (Notes)	Dec. 31, 2016
Going Concern [Abstract]
Basis of Accounting [Text Block]	GOING CONCERN This Partnership has historically funded its operations with cash flows from operations. This Partnership’s most significant cash outlays have related to its operating expenses, capital program and distributions to partners. The market price for crude oil, natural gas, and NGLs decreased significantly during the fourth quarter of 2015, with continued weakness through the first half of 2016. Although this Partnership experienced an increase in sales in 2016 of $46,000 , or 6% , to $825,000 in 2016 compared to $780,000 in 2015 related to an increase in production due to reduced line pressures, the negative impact to its liquidity resulting from declining commodity prices raises substantial doubt about this Partnership’s ability to continue as a going concern. While this Partnership generated modest positive cash flows from operations during 2016, due to anticipated future capital expenditures required to remain in compliance with certain regulatory requirements and to satisfy asset retirement obligations, the Managing General Partner believes that cash flows from operations will be insufficient to meet this Partnership’s obligations. To the extent that the costs of plugging and abandonment activities exceed available cash flows generated by this Partnership's operations, the Managing General Partner expects to fund such activities. The Managing General Partner would recover amounts funded from future cash flows of this Partnership, if available. One of this Partnership's most significant obligations is to the Managing General Partner, which is currently due, for reimbursement of costs paid on behalf of this Partnership by the Managing General Partner. Such amounts are generally paid to third parties for general and administrative expenses and equipment and operating costs, as well as monthly operating fees payable to the Managing General Partner. Beginning in the second quarter of 2015, this Partnership made no quarterly cash distributions to the Managing General Partner or Investor Partners, and the distributions will be suspended beginning in the first quarter of 2017 until such time that cash flows can support the necessary costs of plugging and abandoning the wells that are becoming unproductive or require capital investments that are unsupportable at current commodity prices. The ability of this Partnership to continue as a going concern is dependent upon its ability to attain a satisfactory level of cash flows from operations. Greater cash flow would most likely occur from improved commodity pricing and, to a lesser extent, a sustained increase in production. However, historically, as a result of the normal production decline in a well's production life cycle, this Partnership has not experienced a sustained increase in production without capital expenditures. The Managing General Partner is considering various options to mitigate risks that raise substantial doubt about this Partnership’s ability to continue as a going concern, including, but not limited to, deferral of obligations, continued suspension of distributions to partners, and partial or complete sale of assets. However, there can be no assurance that this Partnership will be able to mitigate such conditions. Failure to do so could result in a partial asset sale or some form of bankruptcy, liquidation, or dissolution of this Partnership. The accompanying financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets and satisfaction of liabilities and commitments in the normal course of business. The financial statements do not reflect any adjustments that might result if this Partnership is unable to continue as a going concern.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
Summary of Significant Accounting Policies	Dec. 31, 2016
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 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 these expenses. Inventory. Inventory consists of crude oil, stated at the lower of cost to produce or market. 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. 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. 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 results of operations. 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, a Level 3 fair value input, 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. 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's crude oil, natural gas and NGLs sales are recorded under either the “net-back” or "gross" method of accounting, depending upon the transportation method used. This Partnership 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 collects a price 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. The net-back method results in the recognition of a sales price that is below the indices for which the production is based. This Partnership uses the gross method of accounting for crude oil delivered through the White Cliffs pipeline as the purchasers do not provide transportation, gathering or processing. Under this method, this Partnership recognizes revenues based on the gross selling price. Recently Adopted Accounting Standard 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 requires management to assess an entity's ability to continue as a going concern at the end of every reporting period and to provide related footnote disclosures in certain circumstances. The new standard was effective for all entities in the first annual period ending after December 15, 2016, with early adoption permitted. This Partnership adopted this standard in the fourth quarter of 2016. Recently Issued Accounting Standard In May 2014, the FASB and the International Accounting Standards Board 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. In August 2015, the FASB deferred the effective date of the revenue standard to annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The revenue standard can be adopted under the full retrospective method or simplified transition method. Entities are permitted to adopt the revenue standard early, beginning with annual reporting periods after December 15, 2016. The Managing General Partner of this Partnership is currently evaluating the impact these changes will have on this Partnership's financial statements.

Fair Value of Financial Instrum

Fair Value of Financial Instruments	12 Months Ended
Fair Value of Financial Instruments	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value Disclosures [Text Block]	FAIR VALUE MEASUREMENTS 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. 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.

Concentration of Risk

Concentration of Risk	12 Months Ended
Concentration of Risk	Dec. 31, 2016
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 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, 2016 and 2015 , this Partnership did not record an allowance for doubtful accounts and did not incur any losses on accounts receivable. As of December 31, 2016 and 2015, this Partnership had two and three customers representing 10 percent or more of the accounts receivable balances. Major Customers. The following table presents the individual customers constituting 10 percent or more of total revenues: Year ended December 31, Major Customer 2016 2015 Suncor Energy Marketing, Inc. 67% 58% DCP Midstream, LP 23% 20% Concord Energy, LLC —% 22%

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
Asset Retirement Obligations	Dec. 31, 2016
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, 2016 2015 Balance at beginning of period $ 2,191,433 $ 1,673,982 Revisions in estimated cash flows 319,436 390,715 Obligations discharged with asset retirements (147,713 ) — Accretion expense 166,273 126,736 Balance at end of period 2,529,429 2,191,433 Less current portion (977,500 ) (345,000 ) Long-term portion $ 1,551,929 $ 1,846,433 This Partnership's estimated asset retirement obligation liability is based on historical experience in plugging and abandoning wells, estimated economic lives, estimated plugging and abandonment cost, and federal and state regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. In 2016, the credit-adjusted risk-free rates used to discount this Partnership's plugging and abandonment liabilities ranged from 6.5 percent to 8.2 percent. In periods subsequent to initial measurement of the liability, this Partnership must recognize period-to-period changes in the liability resulting from the passage of time, revisions to either the amount of the original estimate of undiscounted cash flows or changes in inflation factors and changes to this Partnership's credit-adjusted risk-free rate as market conditions warrant. The revisions in estimated cash flows during 2016 were due to a decrease in the estimated useful life of the wells, which resulted in an increase to the asset retirement obligation liability and a corresponding increase to crude oil and natural gas properties. The revisions in estimated cash flows during 2015 were due to changes in estimates of costs for materials and services related to the plugging and abandonment of certain vertical wells, as well as a decrease in the estimated useful life of these wells. The current portion of the asset retirement obligations relates to 15 to 20 wells that are expected to be plugged and abandoned within the next 12 months.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
Commitments and Contingencies	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies Disclosure [Text Block]	COMMITMENTS AND CONTINGENCIES Litigation and Legal Items. 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 recorded 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. The Managing General Partner is not currently aware of any environmental claims existing as of December 31, 2016 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. In August 2015, the Managing General Partner received an Information Request from the EPA. The Information Request sought, among other things, information related to the design, operation, and maintenance of the Managing General Partner's Wattenberg Field production facilities in the Denver-Julesburg Basin of Colorado. The Information Request focused on historical operation and design information for 46 of the Managing General Partner's production facilities, of which one relates to this Partnership, and asks that it conduct sampling and analyses at the identified 46 facilities. These 46 facilities include four of this Partnership's wells. The Managing General Partner responded to the Information Request in January 2016. Throughout 2016, it continued to meet with the EPA, U.S. Department of Justice, and Colorado Department of Public Health and Environment, and in December 2016 it received a draft consent decree from the EPA. In addition, in December 2015, the Managing General Partner received a Compliance Advisory pursuant to C.R.S. § 25-7-115(2) from the Colorado Department of Public Health and Environment's Air Quality Control Commission's Air Pollution Control Division alleging that the Managing General Partner failed to design, operate, and maintain certain condensate collection, storage, processing, and handling operations to minimize leakage of volatile organic compounds at 65 Wattenberg Field production facilities consistent with applicable standards under Colorado law. These 65 facilities include four of this Partnership's wells. These four partnership wells are the same wells identified in the EPA Information Request noted in the previous paragraph. The ultimate outcome related to this action has not been determined at this time. This matter has been combined with the matter discussed above. The ultimate outcome related to these combined actions has not been determined at this time.

Partners' Equity and Cash Distr

Partners' Equity and Cash Distributions	12 Months Ended
Partners' Equity and Cash Distributions	Dec. 31, 2016
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 % 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. Since this partnership has not made any cash distributions to the Investor Partners in over 12 months, the unit repurchase program is unable to purchase units from Investor Partners. In accordance with the Partnership Agreement, the Managing General Partner has elected to suspend cash distributions, beginning in the first quarter of 2017, in order to fund the plugging and abandonment costs of certain Partnership wells. Since the formula for the repurchase price is set at a minimum of four times the most recent 12 months of cash distributions, due to this Partnership making no cash distributions over the most recent 12 months, the Managing General Partner is unable to repurchase units as there is no value upon which to base the calculation. In any calendar year, the Managing General Partner is conditionally obligated to purchase Investor Partner units aggregating up to 10 percent 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. The Managing General Partners did not have any limited partner unit repurchases during the three months ended December 31, 2016 . 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. Beginning in the second quarter of 2015, the frequency of cash distributions, if any, was changed to a quarterly basis. Additionally, as the wells have gotten older and the likelihood of plugging and abandonment activities are more likely to occur in the foreseeable future, the Managing General Partner has elected to suspend distributions, beginning in the first quarter of 2017, to cover the costs of necessary plugging and abandonment activities. As a result of the impact to the cash distribution policy, if cash were to become available in excess of the plugging and abandonment activities, the Managing General Partner would likely hold cash distributions until the current asset retirement obligations are significantly reduced. Based on current economic conditions, it appears likely that the costs of plugging and abandonment operations will exceed available cash and earnings from this Partnership. The Managing General Partner makes cash distributions of 63 percent to the Investor Partners and 37 percent to the Managing General Partner. Cash distributions began in May 2007 . This Partnership has made no quarterly cash distributions to the Managing General Partner or Investor Partners since the first quarter of 2015. The following table presents the cash distributions made to the Investor Partners and Managing General Partner during the years indicated: Year Ended December 31, 2016 2015 Cash distributions $ — $ 47,167

Transactions with Managing Gene

Transactions with Managing General Partner	12 Months Ended
Transactions with Managing General Partner	Dec. 31, 2016
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, 2016 2015 Crude oil, natural gas and NGLs sales revenues $ 76,028 $ 59,824 Other (1) (398,277 ) (195,304 ) Total Due to Managing General Partner-other, net $ (322,249 ) $ (135,480 ) (1) All other unsettled transactions between this Partnership and the Managing General Partner, the majority of which are capital expenditures, operating costs and general and administrative costs which have not been deducted from distributions. Included in the amount as of December 31, 2016 is $46,257 due to the Managing General Partner for purchases of well equipment. The following table presents Partnership transactions with the Managing General Partner for the years ended December 31, 2016 and 2015 . “Well operations and maintenance” are included in the “Crude oil, natural gas, and NGLs production costs” line item on the statements of operations. Year Ended December 31, 2016 2015 Well operations and maintenance (1) $ 592,903 $ 633,271 Direct costs - general and administrative (2) 177,663 163,009 Cash distributions (3) — 18,219 (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) 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. (3) 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 year ended December 31, 2015 include $767 related to equity cash distributions for Investor Partner units that have been repurchased by PDC.

Impairment of Capitalized Costs

Impairment of Capitalized Costs	12 Months Ended
Impairment of Capitalized Costs	Dec. 31, 2016
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Impairment of natural gas and crude oil properties [Table Text Block]	IMPAIRMENT OF CRUDE OIL AND NATURAL GAS PROPERTIES In 2015, this Partnership recognized an impairment charge of approximately $4.6 million to write-down its proved crude oil and natural gas properties. The impairment charge represented the amount by which the carrying value of the crude oil and natural gas properties exceeded the estimated fair value, and was therefore not recoverable. The estimated fair value of approximately $479,000 , excluding estimated salvage value of $471,000 , was determined based on estimated future discounted net cash flows, a Level 3 input, using estimated production and future crude oil and natural gas prices which the Managing General Partner reasonably expects this Partnership's crude oil and natural gas will be sold and decreased reserve quantities . This Partnership did not record an impairment charge in 2016.

Supplemental Crude Oil, Natural

Supplemental Crude Oil, Natural Gas and NGL Information - Unaudited	12 Months Ended
	Dec. 31, 2016
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Oil and Gas Exploration and Production Industries Disclosures [Text Block]	Net Proved Reserves All of this Partnership's crude oil, natural gas, and NGLs reserves are located in the U.S. This Partnership utilized the services of an independent petroleum engineer to estimate this Partnership's 2016 and 2015 crude oil, natural gas, and NGLs reserves. As of December 31, 2016 and 2015, all of this Partnership's estimates of proved reserves were based on reserve reports prepared by Ryder Scott Company, L.P. 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, 2016 and 2015 , there are no proved undeveloped reserves for this Partnership. The following table presents the indicated index price for our reserves, as required by SEC regulations and are referred to as SEC commodity prices: Average Benchmark Prices As of December 31, Crude Oil (per Bbl) Natural Gas (per Mcf) NGLs (per Bbl) 2016 $ 42.75 $ 2.48 $ 42.75 2015 50.28 2.58 50.28 The following table presents the netted back prices used to estimate this Partnership's reserves, by commodity. The prices used to estimate reserves have been prepared in accordance with SEC commodity prices. 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. Price Used to Estimate Reserves As of December 31, Crude Oil (per Bbl) Natural Gas (per Mcf) NGLs (per Bbl) 2016 $ 38.70 $ 1.95 $ 10.79 2015 42.07 2.07 10.60 The following table presents the changes in estimated quantities of this Partnership's reserves, all of which are located within the United States: Crude Oil and Condensate Natural Gas NGLs Crude Oil Equivalent (MBbl) (MMcf) (MBbl) (MBoe) Proved Reserves: Proved reserves, January 1, 2015 158 1,192 140 497 Revisions of previous estimates and reclassifications (102 ) (1,015 ) (115 ) (386 ) Production (16 ) (44 ) (6 ) (29 ) Proved reserves, December 31, 2015 40 133 19 82 Revisions of previous estimates and reclassifications 21 133 18 61 Production (16 ) (56 ) (8 ) (33 ) Proved reserves, December 31, 2016 45 210 29 110 Proved Developed Reserves, as of: December 31, 2015 40 133 19 82 December 31, 2016 45 210 29 110 2016 Activity. As of December 31, 2016, this Partnership recorded an upward revision of its previous estimate of proved reserves by approximately 61 MBoe. The revision includes upward revisions to previous estimates of 21 MBbl of crude oil, 133 MMcf of natural gas, and 18 MBbl of NGLs. The upward revisions were the result of reductions in gathering system line pressures, which has enhanced the productive profile of some of this Partnership's wells. There were no proved undeveloped reserves developed in 2016 and no proved undeveloped reserves attributable to this Partnership's assets as of December 31, 2016. 2015 Activity. As of December 31, 2015, this Partnership recorded a downward revision of its previous estimate of proved reserves by approximately 386 MBoe. The revision includes downward revisions to previous estimates of 102 MBbl of crude oil, 1,015 MMcf of natural gas, and 115 MBbl of NGLs. The downward revisions were the result of reduced asset performance. There were no proved undeveloped reserves developed in 2015 and no proved undeveloped reserves attributable to this Partnership's assets as of December 31, 2015. Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves The standardized measure below has been prepared in accordance with U.S. GAAP. 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 our year-end estimated proved reserves. Prices for each year were adjusted for Btu content and transportation. Production, development and abandonment costs were based on prices as of December 31 for each of the respective years presented. The amounts shown do not give effect to non-property related expenses, such as corporate general and administrative expenses, or to depreciation, depletion, and amortization expense. No income taxes were considered in the standardized measure as this Partnership is not subject to income tax. The following table presents information with respect to the standardized measure of discounted future net cash flows relating to proved reserves. Changes in the demand for crude oil, natural gas, and NGLs, inflation and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of our proved reserves. As of December 31, 2016 2015 Future estimated cash flows $ 2,490,900 $ 2,174,400 Future estimated production costs (1,707,000 ) (1,386,800 ) Future estimated abandonment costs (3,043,100 ) (949,300 ) Future net cash flows (2,259,200 ) (161,700 ) 10% annual discount for estimated timing of cash flows 704,100 119,300 Standardized measure of discounted future estimated net cash flows $ (1,555,100 ) $ (42,400 ) 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 September 2006 . This Partnership currently owns an undivided working interest in 59 gross ( 58.9 net) productive crude oil and natural gas wells located in the Wattenberg Field within the Denver-Julesburg Basin, northeast 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, 2016 2015 Leasehold costs $ 126,373 $ 8,004 Development costs (1) 1,769,437 1,513,442 Crude oil and natural gas properties, successful efforts method, at cost 1,895,810 1,521,446 Less: Accumulated DD&A (779,728 ) (571,528 ) Crude oil and natural gas properties, net $ 1,116,082 $ 949,918 (1) Includes estimated costs associated with this Partnership's asset retirement obligations. 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.

Going Concern (Policies)

Going Concern (Policies)	12 Months Ended
Going Concern (Policies)	Dec. 31, 2016
Going Concern [Abstract]
Liquidation Basis of Accounting [Text Block]	This Partnership has historically funded its operations with cash flows from operations. This Partnership’s most significant cash outlays have related to its operating expenses, capital program and distributions to partners. The market price for crude oil, natural gas, and NGLs decreased significantly during the fourth quarter of 2015, with continued weakness through the first half of 2016. Although this Partnership experienced an increase in sales in 2016 of $46,000 , or 6% , to $825,000 in 2016 compared to $780,000 in 2015 related to an increase in production due to reduced line pressures, the negative impact to its liquidity resulting from declining commodity prices raises substantial doubt about this Partnership’s ability to continue as a going concern. While this Partnership generated modest positive cash flows from operations during 2016, due to anticipated future capital expenditures required to remain in compliance with certain regulatory requirements and to satisfy asset retirement obligations, the Managing General Partner believes that cash flows from operations will be insufficient to meet this Partnership’s obligations. To the extent that the costs of plugging and abandonment activities exceed available cash flows generated by this Partnership's operations, the Managing General Partner expects to fund such activities. The Managing General Partner would recover amounts funded from future cash flows of this Partnership, if available. One of this Partnership's most significant obligations is to the Managing General Partner, which is currently due, for reimbursement of costs paid on behalf of this Partnership by the Managing General Partner. Such amounts are generally paid to third parties for general and administrative expenses and equipment and operating costs, as well as monthly operating fees payable to the Managing General Partner. Beginning in the second quarter of 2015, this Partnership made no quarterly cash distributions to the Managing General Partner or Investor Partners, and the distributions will be suspended beginning in the first quarter of 2017 until such time that cash flows can support the necessary costs of plugging and abandoning the wells that are becoming unproductive or require capital investments that are unsupportable at current commodity prices. The ability of this Partnership to continue as a going concern is dependent upon its ability to attain a satisfactory level of cash flows from operations. Greater cash flow would most likely occur from improved commodity pricing and, to a lesser extent, a sustained increase in production. However, historically, as a result of the normal production decline in a well's production life cycle, this Partnership has not experienced a sustained increase in production without capital expenditures. The Managing General Partner is considering various options to mitigate risks that raise substantial doubt about this Partnership’s ability to continue as a going concern, including, but not limited to, deferral of obligations, continued suspension of distributions to partners, and partial or complete sale of assets. However, there can be no assurance that this Partnership will be able to mitigate such conditions. Failure to do so could result in a partial asset sale or some form of bankruptcy, liquidation, or dissolution of this Partnership. The accompanying financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets and satisfaction of liabilities and commitments in the normal course of business. The financial statements do not reflect any adjustments that might result if this Partnership is unable to continue as a going concern.

Summary of Significant Accoun19

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
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, future cash flows from crude oil and natural gas properties 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. It is reasonably possible that the Managing General Partner's estimate of uncollectible receivables will change periodically
Inventory, Policy [Policy Text Block]	Inventory consists of crude oil, stated at the lower of cost to produce or market
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. 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. 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 results of operations.
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, a Level 3 fair value input, 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's crude oil, natural gas and NGLs sales are recorded under either the “net-back” or "gross" method of accounting, depending upon the transportation method used. This Partnership 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 collects a price 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. The net-back method results in the recognition of a sales price that is below the indices for which the production is based. This Partnership uses the gross method of accounting for crude oil delivered through the White Cliffs pipeline as the purchasers do not provide transportation, gathering or processing. Under this method, this Partnership recognizes revenues based on the gross selling price.
Accounting Standards Recently Adopted [Policy Text Block]	Recently Adopted Accounting Standard 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 requires management to assess an entity's ability to continue as a going concern at the end of every reporting period and to provide related footnote disclosures in certain circumstances. The new standard was effective for all entities in the first annual period ending after December 15, 2016, with early adoption permitted. This Partnership adopted this standard in the fourth quarter of 2016. Recently Issued Accounting Standard In May 2014, the FASB and the International Accounting Standards Board 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. In August 2015, the FASB deferred the effective date of the revenue standard to annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The revenue standard can be adopted under the full retrospective method or simplified transition method. Entities are permitted to adopt the revenue standard early, beginning with annual reporting periods after December 15, 2016. The Managing General Partner of this Partnership is currently evaluating the impact these changes will have on this Partnership's financial statements.
New Accounting Pronouncement, Early Adoption [Table Text Block]	Recently Adopted Accounting Standard 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 requires management to assess an entity's ability to continue as a going concern at the end of every reporting period and to provide related footnote disclosures in certain circumstances. The new standard was effective for all entities in the first annual period ending after December 15, 2016, with early adoption permitted. This Partnership adopted this standard in the fourth quarter of 2016.
Description of New Accounting Pronouncements Not yet Adopted [Text Block]	Recently Issued Accounting Standard In May 2014, the FASB and the International Accounting Standards Board 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. In August 2015, the FASB deferred the effective date of the revenue standard to annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The revenue standard can be adopted under the full retrospective method or simplified transition method. Entities are permitted to adopt the revenue standard early, beginning with annual reporting periods after December 15, 2016. The Managing General Partner of this Partnership is currently evaluating the impact these changes will have on this Partnership's financial statements.

Concentration of Risk Concentra

Concentration of Risk Concentration of Risk (Tables)	12 Months Ended
Concentration of Risk Concentration of Risk (Tables)	Dec. 31, 2016
Concentration Risk - Revenue
Individual Customers Constituting 10% or more of Total Revenue [Table Text Block]	The following table presents the individual customers constituting 10 percent or more of total revenues: Year ended December 31, Major Customer 2016 2015 Suncor Energy Marketing, Inc. 67% 58% DCP Midstream, LP 23% 20% Concord Energy, LLC —% 22%

Asset Retirement Obligations As

Asset Retirement Obligations Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 2015 Balance at beginning of period $ 2,191,433 $ 1,673,982 Revisions in estimated cash flows 319,436 390,715 Obligations discharged with asset retirements (147,713 ) — Accretion expense 166,273 126,736 Balance at end of period 2,529,429 2,191,433 Less current portion (977,500 ) (345,000 ) Long-term portion $ 1,551,929 $ 1,846,433

Partners' Equity and Cash Dis22

Partners' Equity and Cash Distributions (Tables)	12 Months Ended
Partners' Equity and Cash Distributions (Tables)	Dec. 31, 2016
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 % 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

Partners' Equity and Cash Dis23

Partners' Equity and Cash Distributions Cash Distributions (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 2015 Cash distributions $ — $ 47,167

Transactions with Managing Ge24

Transactions with Managing General Partner Transactions with Managing General Partner (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 2015 Crude oil, natural gas and NGLs sales revenues $ 76,028 $ 59,824 Other (1) (398,277 ) (195,304 ) Total Due to Managing General Partner-other, net $ (322,249 ) $ (135,480 ) (1) All other unsettled transactions between this Partnership and the Managing General Partner, the majority of which are capital expenditures, operating costs and general and administrative costs which have not been deducted from distributions. Included in the amount as of December 31, 2016 is $46,257 due to the Managing General Partner for purchases of well equipment.
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, 2016 and 2015 . “Well operations and maintenance” are included in the “Crude oil, natural gas, and NGLs production costs” line item on the statements of operations. Year Ended December 31, 2016 2015 Well operations and maintenance (1) $ 592,903 $ 633,271 Direct costs - general and administrative (2) 177,663 163,009 Cash distributions (3) — 18,219 (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) 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. (3) 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 year ended December 31, 2015 include $767 related to equity cash distributions for Investor Partner units that have been repurchased by PDC.

Supplemental Crude Oil, Natur25

Supplemental Crude Oil, Natural Gas and NGL Information - Unaudited Supplemental Crude Oil, Natural Gas and NGL Information - Unaudited (Tables)	12 Months Ended
	Dec. 31, 2016
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Index price for reserves, by commodity [Table Text Block]	The following table presents the indicated index price for our reserves, as required by SEC regulations and are referred to as SEC commodity prices: Average Benchmark Prices As of December 31, Crude Oil (per Bbl) Natural Gas (per Mcf) NGLs (per Bbl) 2016 $ 42.75 $ 2.48 $ 42.75 2015 50.28 2.58 50.28
Schedule of Prices Used to Estimate Crude Oil and Natural Gas Reserves [Table Text Block]	The following table presents the netted back prices used to estimate this Partnership's reserves, by commodity. The prices used to estimate reserves have been prepared in accordance with SEC commodity prices. 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. Price Used to Estimate Reserves As of December 31, Crude Oil (per Bbl) Natural Gas (per Mcf) NGLs (per Bbl) 2016 $ 38.70 $ 1.95 $ 10.79 2015 42.07 2.07 10.60
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, 2016 2015 Leasehold costs $ 126,373 $ 8,004 Development costs (1) 1,769,437 1,513,442 Crude oil and natural gas properties, successful efforts method, at cost 1,895,810 1,521,446 Less: Accumulated DD&A (779,728 ) (571,528 ) Crude oil and natural gas properties, net $ 1,116,082 $ 949,918 (1) Includes estimated costs associated with this Partnership's asset retirement obligations.
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block]	The following table presents information with respect to the standardized measure of discounted future net cash flows relating to proved reserves. Changes in the demand for crude oil, natural gas, and NGLs, inflation and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of our proved reserves. As of December 31, 2016 2015 Future estimated cash flows $ 2,490,900 $ 2,174,400 Future estimated production costs (1,707,000 ) (1,386,800 ) Future estimated abandonment costs (3,043,100 ) (949,300 ) Future net cash flows (2,259,200 ) (161,700 ) 10% annual discount for estimated timing of cash flows 704,100 119,300 Standardized measure of discounted future estimated net cash flows $ (1,555,100 ) $ (42,400 )

General and Basis of Presenta26

General and Basis of Presentation General and Basis of Presentation (Details)	12 Months Ended
	Dec. 31, 2016Number_of_Limited_Partners$ / sharesRateshares
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of Limited Partners \| Number_of_Limited_Partners	1,975
Managing General Partner, Ownership Interest Before Unit Repurchases	37.00%
Investor Partner Ownership Interest	63.00%
Limited Partner Units Repurchased by Managing General Partner \| shares	163.8
Average Price Paid for Units Repurchased by Managing General Partner \| $ / shares	$ 2,351
Managing General Partner Ownership Interest	39.30%

Going Concern (Details)

Going Concern (Details) - USD ($)	12 Months Ended
Going Concern (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Going Concern [Abstract]
Increase (Decrease) in crude oil, natural gas and NGLs sales	$ 46,000
Percentage Increase (Decrease) in Crude Oil, Natural Gas and NGLs sales	6.00%
Crude Oil, natural gas and NGLs sales	$ 825,271	$ 779,509

Summary of Significant Accoun28

Summary of Significant Accounting Policies Summary of significant accounting policies (Details)	Dec. 31, 2016USD ($)
Cash and Cash Equivalents [Line Items]
Cash, FDIC Insured Amount	$ 250,000

Concentration of Risk Concent29

Concentration of Risk Concentration of Risk (Details)	12 Months Ended
Concentration of Risk Concentration of Risk (Details)	Dec. 31, 2016Rate	Dec. 31, 2015Rate
Suncor Energy Marketing, Inc.
Concentration Risk - Revenue
Percentage of Partnership Revenue	67.00%	58.00%
DCP Midstream, LP [Member]
Concentration Risk - Revenue
Percentage of Partnership Revenue	23.00%	20.00%
Concord Energy [Member]
Concentration Risk - Revenue
Percentage of Partnership Revenue	0.00%	22.00%

Asset Retirement Obligations 30

Asset Retirement Obligations Asset Retirement Obligations (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Changes in Carrying Amounts of the Asset Retirement Obligation
Balance at beginning of year	$ 2,191,433	$ 1,673,982
Revision of estimated cash flows	319,436	390,715
Asset Retirement Obligations	(147,713)	0
Accretion expense	166,273	126,736
Balance at end of year	2,529,429	2,191,433
Asset Retirement Obligation, Current	(977,500)	(345,000)
Asset Retirement Obligations, Noncurrent	$ 1,551,929	$ 1,846,433

Asset Retirement Obligations Cu

Asset Retirement Obligations Current portion of ARO related to wells plugged (Details)	Dec. 31, 2016Wells
Minimum [Member]
Current portion of ARO related to wells plugged [Line Items]
OIl and Gas Wells Expected to be Plugged	15
Maximum [Member]
Current portion of ARO related to wells plugged [Line Items]
OIl and Gas Wells Expected to be Plugged	20

Partners' Equity and Cash Dis32

Partners' Equity and Cash Distributions Partners' Equity and Cash Distributions (Details)	12 Months Ended
	Dec. 31, 2016Rate
Investor Partners
Allocation of Partners' Interest
Crude oil, natural gas and NGLs sales	63.00%
Sale of Productive Properties	63.00%
Sale of Equipment	63.00%
Interest Income	63.00%
Crude Oil, Natural Gas and NGLs Production and Well Operations Costs	63.00%	[1]
Depreciation, Depletion and Amortization Expense	63.00%
Accretion of Asset Retirement Obligations	63.00%
Direct Costs - General and Administrative	63.00%	[2]
Managing General Partner
Allocation of Partners' Interest
Crude oil, natural gas and NGLs sales	37.00%
Sale of Productive Properties	37.00%
Sale of Equipment	37.00%
Interest Income	37.00%
Crude Oil, Natural Gas and NGLs Production and Well Operations Costs	37.00%	[1]
Depreciation, Depletion and Amortization Expense	37.00%
Accretion of Asset Retirement Obligations	37.00%
Direct Costs - General and Administrative	37.00%	[2]

[1]	Represents operating costs incurred after the completion of productive wells, including monthly per-well charges paid to the Managing General Partner.
[2]	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.

Partners' Equity and Cash Dis33

Partners' Equity and Cash Distributions Cash Distributions (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Distributions made to limited partner and managing partner of limited partnership. [Line Items]
Investor Partner Ownership Interest	63.00%
Managing General Partner, Ownership Interest Before Unit Repurchases	37.00%
Partners' Capital Account Distributions During the Year	$ 0	$ 47,167
Performance Standard Obligation of Managing General Partner
Percentage of Obligated Unit Repurchases	10.00%

Transactions with Managing Ge34

Transactions with Managing General Partner Undistributed or Unsettled Transactions With Investor Partners (Details) - USD ($)		Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Due from (to) Managing General Partner-other, net		$ (322,249)	$ (135,480)
Crude oil, Natural gas and NGLs sales revenues collected from the Partnership's third-party customers
Related Party Transaction [Line Items]
Due from (to) Managing General Partner-other, net		76,028	59,824
Other
Related Party Transaction [Line Items]
Due from (to) Managing General Partner-other, net	[1]	$ (398,277)	$ (195,304)

[1]	All other unsettled transactions between this Partnership and the Managing General Partner, the majority of which are capital expenditures, operating costs and general and administrative costs which have not been deducted from distributions. Included in the amount as of December 31, 2016 is $46,257 due to the Managing General Partner for purchases of well equipment.

Transactions with Managing Ge35

Transactions with Managing General Partner Related Party Transactions (Details) - USD ($)		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Direct costs - general and administrative		$ 177,663	$ 163,009
Investor Partner Ownership Interest		63.00%
Managing General Partner, Ownership Interest Before Unit Repurchases		37.00%
Managing General Partner
Related Party Transaction [Line Items]
Well operations and maintenance	[1]	$ 592,903	633,271
Direct costs - general and administrative	[2]	177,663	163,009
Cash distributions	[3]	$ 0	18,219
Distribution Made to Limited Partner, Cash Distributions Paid			$ 767

[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]	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.
[3]	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 year ended December 31, 2015 include $767 related to equity cash distributions for Investor Partner units that have been repurchased by PDC.

Impairment of Capitalized Cos36

Impairment of Capitalized Costs Impairment of Capitalized Costs (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of crude oil and natural gas properties	$ 0	$ 4,611,188
Estimated fair value	479,000
Estimated salvage value	$ 471,000
Wattenberg Field
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of crude oil and natural gas properties		$ 4,600,000

Supplemental Crude Oil, Natur37

Supplemental Crude Oil, Natural Gas and NGL Information - Unaudited Average Benchmark Prices (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Crude Oil (MBbl)
Reserve Quantities [Line Items]
oil and gas index price for reserves	$ 42.75	$ 50.28
Natural Gas (MMcf)
Reserve Quantities [Line Items]
oil and gas index price for reserves	2.48	2.58
Natural Gas Liquids (MBbl)
Reserve Quantities [Line Items]
oil and gas index price for reserves	$ 42.75	$ 50.28

Supplemental Crude Oil, Natur38

Supplemental Crude Oil, Natural Gas and NGL Information - Unaudited Price Used to Estimate Reserves (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Oil (MBbl)
Reserve Quantities [Line Items]
Price Used to Estimate Reserves	$ 38.70	$ 42.07
Natural Gas (MMcf)
Reserve Quantities [Line Items]
Price Used to Estimate Reserves	1.95	2.07
Natural Gas Liquids (MBbl)
Reserve Quantities [Line Items]
Price Used to Estimate Reserves	$ 10.79	$ 10.60

Supplemental Crude Oil, Natur39

Supplemental Crude Oil, Natural Gas and NGL Information - Unaudited Schedule of Developed and Undeveloped Reserves (Details)	12 Months Ended
	Dec. 31, 2016MMcfMBbls	Dec. 31, 2015MMcfMBbls
Natural Gas (MMcf)
Reserve Quantities [Line Items]
Proved reserves, January 1, \| MMcf	133	1,192
Revisions of previous estimates and reclassifications \| MMcf	133	(1,015)
Production \| MMcf	(56)	(44)
Proved reserves, December 31, \| MMcf	210	133
Proved Developed Reserves \| MMcf	210	133
Natural Gas Liquids (MBbl)
Reserve Quantities [Line Items]
Proved reserves, January 1,	19	140
Revisions of previous estimates and reclassifications	18	(115)
Production	(8)	(6)
Proved reserves, December 31,	29	19
Proved Developed Reserves	29	19
Crude Oil (MBbl)
Reserve Quantities [Line Items]
Proved reserves, January 1,	40	158
Revisions of previous estimates and reclassifications	21	(102)
Production	(16)	(16)
Proved reserves, December 31,	45	40
Proved Developed Reserves	45	40
Natural Gas Equivalent (MMcfe)
Reserve Quantities [Line Items]
Proved reserves, January 1,	82	497
Revisions of previous estimates and reclassifications	61	(386)
Production	(33)	(29)
Proved reserves, December 31,	110	82
Proved Developed Reserves	110	82

Supplemental Crude Oil, Natur40

Supplemental Crude Oil, Natural Gas and NGL Information - Unaudited Capitalized Costs Related to Crude Oil and Natural Gas Producing Activities (Details)		12 Months Ended
		Dec. 31, 2016USD ($)Wells	Dec. 31, 2015USD ($)
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Leasehold costs		$ 126,373	$ 8,004
Development costs	[1]	1,769,437	1,513,442
Crude oil and natural gas properties, successful efforts method, at cost		1,895,810	1,521,446
Less: Accumulated depreciation, depletion and amortization		(779,728)	(571,528)
Crude oil and natural gas properties, net		$ 1,116,082	949,918
Additional Information:
Oil and natural gas producing wells, gross \| Wells		59
Oil and gas producing wells, net \| Wells		58.9
Payments to Acquire Oil and Gas Equipment		$ 8,671	70,252
Impairment of crude oil and natural gas properties		$ 0	4,611,188
Wattenberg Field
Additional Information:
Impairment of crude oil and natural gas properties			$ 4,600,000

[1]	Includes estimated costs associated with this Partnership's asset retirement obligations.

Supplemental Crude Oil, Natur41

Supplemental Crude Oil, Natural Gas and NGL Information - Unaudited Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Cash Inflows	$ 2,490,900	$ 2,174,400
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows	(2,259,200)	(161,700)
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Production Costs	(1,707,000)	(1,386,800)
future net cash flows relating to proved oil and gas reserves abandonment costs	(3,043,100)	(949,300)
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Ten Percent Annual Discount for Estimated Timing of Cash Flows	704,100	119,300
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves	$ (1,555,100)	$ (42,400)