Rockies Region 2006 Limited Partnership - FORM 10-Q

Attached files

file	filename
EX-31.1 - CERTIFICATION BY CEO PURSUANT TO SECTION 302 OF SARBANES-OXLEY ACT OF 2002 - Rockies Region 2006 Limited Partnership	rr06-ex311_20110930.htm
EX-31.2 - CERTIFICATION BY CFO PURSANT TO SECTION 302 OF SARBANES-OXLEY ACT OF 2002 - Rockies Region 2006 Limited Partnership	rr06-ex312_20110930.htm
EX-32.1 - CERTIFICATIONS BY CEO AND CFO PURSUANT TO SECTION 906 OF SARBANES-OXLEY ACT OF 2002 - Rockies Region 2006 Limited Partnership	rr06-ex321_20110930.htm
EXCEL - IDEA: XBRL DOCUMENT - Rockies Region 2006 Limited Partnership	Financial_Report.xls

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

S QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT

OF 1934

For the quarterly period ended September 30, 2011

£ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT

OF 1934 FOR THE TRANSITION PERIOD ____________ TO ____________

Commission File Number 000-52787

Rockies Region 2006 Limited Partnership

(Exact name of registrant as specified in its charter)



	West Virginia		20-5149573
	(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1775 Sherman Street, Suite 3000, Denver, Colorado 80203

(Address of principal executive offices) (Zip code)

(303) 860-5800

(Registrant's telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.

Yes R No £

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes R No £

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.



	Large accelerated filer £		Accelerated filer £

	Non-accelerated filer £		Smaller reporting company R

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes £ No R

As of September 30, 2011 the Partnership had 4,497.03 units of limited partnership interest and no units of additional general partnership interest outstanding.

Rockies Region 2006 Limited Partnership

(A West Virginia Limited Partnership)

INDEX TO REPORT ON FORM 10-Q



PART I – FINANCIAL INFORMATION
		Page
	Special Note Regarding Forward-Looking Statements	1
Item 1.	Financial Statements (unaudited)
	Condensed Balance Sheets (unaudited)	2
	Condensed Statements of Operations (unaudited)	3
	Condensed Statements of Cash Flows (unaudited)	4
	Notes to Unaudited Condensed Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	13
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	25
Item 4.	Controls and Procedures	25

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	26
Item 1A.	Risk Factors	26
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	26
Item 3.	Defaults Upon Senior Securities	26
Item 4.	[Removed and Reserved]	26
Item 5.	Other Information	26
Item 6.	Exhibits	27

	SIGNATURES	28

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This periodic report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (“Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (“Exchange Act”) regarding Rockies Region 2006 Limited Partnership's (“Partnership” or the “Registrant”) business, financial condition and results of operations. Petroleum Development Corporation (“PDC”), which conducts business under the name PDC Energy, is the Managing General Partner of the Partnership. All statements other than statements of historical facts included in and incorporated by reference into this report are “forward-looking statements” within the meaning of the safe harbor provisions of the United States Private Securities Litigation Reform Act of 1995. Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein. These statements include: estimated natural gas, natural gas liquid(s) or “NGL(s)” and crude oil production and reserves; drilling plans; future cash flows and anticipated liquidity; anticipated capital expenditures; the adequacy of the Managing General Partner's casualty insurance coverage; the effectiveness of the Managing General Partner's derivative policies in achieving the Partnership's risk management objectives; and the Managing General Partner's strategies, plans and objectives.

The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect the Managing General Partner's good faith judgment, such statements can only be based on facts and factors currently known to the Managing General Partner. Consequently, forward-looking statements are inherently subject to risks and uncertainties, including known and unknown risks and uncertainties incidental to the development, production and marketing of natural gas, NGLs and crude oil, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements.

Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:


•	changes in production volumes and worldwide demand;


•	volatility of commodity prices for natural gas, NGLs and crude oil;


•	changes in estimates of proved reserves;


•	inaccuracy of reserve estimates and expected production rates;


•	declines in the value of the Partnership's natural gas and crude oil properties resulting in impairments;


•	the availability of Partnership future cash flows for investor distributions or funding of refracturing activities;


•	the timing and extent of the Partnership's success in further developing and producing the Partnership's reserves;


•	the Managing General Partner's ability to acquire drilling rig services, supplies and services at reasonable prices;


•	risks incidental to the refracturing and operation of natural gas and crude oil wells;


•	the availability of sufficient pipeline and other transportation facilities to carry Partnership production and the impact of these facilities on price;


•	changes in environmental laws, the regulation and enforcement of those laws and the costs to comply with those laws;


•	the impact of environmental events, governmental responses to the events and the Managing General Partner's ability to insure adequately against such events;


•	the timing and receipt of necessary regulatory permits;


•	competition in the oil and gas industry;


•	the success of the Managing General Partner in marketing the Partnership's natural gas, NGLs and crude oil;


•	the effect of natural gas and crude oil derivative activities;


•	the cost of pending or future litigation;


•	the Managing General Partner's ability to retain or attract senior management and key technical employees; and


•	the success of strategic plans, expectations and objectives for future operations of the Managing General Partner.

Further, the Partnership urges the reader to carefully review and consider the cautionary statements and disclosures made in this report, the Partnership's annual report on Form 10-K for the year ended December 31, 2010 filed with the United States Securities and Exchange Commission (“SEC”) on March 30, 2011 (“2010 Form 10-K”) and the Partnership's other filings with the SEC for further information on risks and uncertainties that could affect the Partnership's business, financial condition and results of operations, which are incorporated by this reference as though fully set forth herein. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date of this report. The Partnership undertakes no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. All forward looking statements are qualified in their entirety by this cautionary statement.

-1-

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements (unaudited)

Rockies Region 2006 Limited Partnership

Condensed Balance Sheets

(unaudited)



	September 30, 2011			December 31, 2010*
Assets

Current assets:
Cash and cash equivalents	$	1,722,783		$	472,783
Accounts receivable	459,941			757,922
Crude oil inventory	66,739			54,523
Due from Managing General Partner-derivatives	2,417,825			1,878,527
Due from Managing General Partner-other, net	324,424			557,042
Total current assets	4,991,712			3,720,797

Natural gas and crude oil properties, successful efforts method, at cost	54,867,324			54,762,691
Less: Accumulated depreciation, depletion and amortization	(27,974,669		)	(25,720,416		)
Natural gas and crude oil properties, net	26,892,655			29,042,275

Due from Managing General Partner-derivatives	2,207,052			2,862,389
Assets held for sale	—			2,363,204
Other assets	50,943			13,346
Total non current assets	29,150,650			34,281,214

Total Assets	$	34,142,362		$	38,002,011

Liabilities and Partners' Equity

Current liabilities:
Accounts payable and accrued expenses	$	80,485		$	213,998
Due to Managing General Partner-derivatives	1,400,719			1,594,290
Total current liabilities	1,481,204			1,808,288

Due to Managing General Partner-derivatives	1,448,913			2,172,721
Asset retirement obligations	943,398			1,098,625
Total liabilities	3,873,515			5,079,634

Commitments and contingent liabilities

Partners' equity:
Managing General Partner	6,263,459			7,245,266
Limited Partners - 4,497.03 units issued and outstanding	24,005,388			25,677,111
Total Partners' equity	30,268,847			32,922,377

Total Liabilities and Partners' Equity	$	34,142,362		$	38,002,011

*Derived from audited 2010 balance sheet

See accompanying notes to unaudited condensed financial statements.

-2-

Rockies Region 2006 Limited Partnership

Condensed Statements of Operations

(unaudited)



	Three months ended September 30,				Nine months ended September 30,
	2011		2010		2011		2010
Revenues:
Natural gas, NGLs and crude oil sales	$	1,565,706	$	1,912,987	$	5,112,731	$	7,054,112
Commodity price risk management gain, net	873,628		1,776,663		1,097,609		5,223,103
Total revenues	2,439,334		3,689,650		6,210,340		12,277,215

Operating costs and expenses:
Natural gas, NGLs and crude oil production costs	613,030		752,385		2,260,623		2,219,326
Direct costs - general and administrative	46,140		35,402		133,860		119,072
Depreciation, depletion and amortization	707,030		1,535,375		2,254,253		5,042,104
Accretion of asset retirement obligations	13,155		14,998		38,908		44,368
Total operating costs and expenses	1,379,355		2,338,160		4,687,644		7,424,870

Income from continuing operations	1,059,979		1,351,490		1,522,696		4,852,345

Interest income	3,352		—		3,352		—

Net income from continuing operations	1,063,331		1,351,490		1,526,048		4,852,345
Income from discontinued operations	—		170,210		3,663,731		630,436

Net income	$	1,063,331	$	1,521,700	$	5,189,779	$	5,482,781

Net income allocated to partners	$	1,063,331	$	1,521,700	$	5,189,779	$	5,482,781
Less: Managing General Partner interest in net income	393,432		563,029		1,920,218		2,028,629
Net income allocated to Investor Partners	$	669,899	$	958,671	$	3,269,561	$	3,454,152

Net income per Investor Partner unit	$	149	$	213	$	727	$	768

Investor Partner units outstanding	4,497.03		4,497.03		4,497.03		4,497.03

See accompanying notes to unaudited condensed financial statements.

-3-

Rockies Region 2006 Limited Partnership

Condensed Statements of Cash Flows

(unaudited)



	Nine months ended September 30,
	2011			2010
Cash flows from operating activities:
Net income	$	5,189,779		$	5,482,781
Adjustments to net income to reconcile to net cash provided by operating activities:
Depreciation, depletion and amortization	2,254,253			5,335,507
Accretion of asset retirement obligations	38,908			44,368
Unrealized gain on derivative transactions	(801,340		)	(3,674,211		)
Gain on sale of natural gas and crude oil properties	(3,515,554		)	—
Changes in operating assets and liabilities:
Decrease in accounts receivable	297,981			289,668
Decrease (increase) in crude oil inventory	(12,216		)	526
Increase in other assets	(37,597		)	—
Increase (decrease) in accounts payable and accrued expenses	(133,513		)	125,828
Decrease in Due from Managing General Partner - other, net	232,618			850,584
Net cash provided by operating activities	3,513,319			8,455,051

Cash flows from investing activities:
Capital expenditures for natural gas and crude oil properties	(104,633		)	(1,189,340		)
Proceeds from sale of natural gas and crude oil properties	5,684,623			—
Net cash provided by (used in) investing activities	5,579,990			(1,189,340		)

Cash flows from financing activities:
Distributions to Partners	(7,843,309		)	(6,918,188		)
Net cash used in financing activities	(7,843,309		)	(6,918,188		)

Net increase in cash and cash equivalents	1,250,000			347,523
Cash and cash equivalents, beginning of period	472,783			5,278
Cash and cash equivalents, end of period	$	1,722,783		$	352,801

Supplemental disclosure of non-cash activity:
Asset retirement obligation, with corresponding decrease to natural gas and crude oil properties	$	(194,135	)	$	—

See accompanying notes to unaudited condensed financial statements.

-4-

ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 2011

(unaudited)

Note 1−General and Basis of Presentation

Rockies Region 2006 Limited Partnership (the “Partnership” or the “Registrant”) 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 natural gas and crude oil properties. Business operations of the Partnership commenced upon closing of an offering for the private placement of Partnership units. Upon funding, the Partnership entered into a Drilling and Operating Agreement (“D&O Agreement”) with the Managing General Partner which authorizes Petroleum Development Corporation (“PDC”), which conducts business under the name PDC Energy, to conduct and manage the Partnership's business. In accordance with the terms of the Limited Partnership Agreement (the “Agreement”), the Managing General Partner is authorized to manage all activities of the Partnership and initiates and completes substantially all Partnership transactions.

As of September 30, 2011, there were 2,020 Investor Partners. PDC is the designated Managing General Partner of the Partnership and owns a 37% Managing General Partner ownership in the Partnership. According to the terms of the Agreement, revenues, costs and cash distributions of the Partnership are allocated 63% to the limited partners (“Investor Partners”), which are shared pro rata, based upon the number of units in the Partnership, and 37% to the Managing General Partner. The Managing General Partner may repurchase Investor Partner units under certain circumstances provided by the Agreement, upon request of an individual Investor Partner. Through September 30, 2011, the Managing General Partner has repurchased 22 units of Partnership interests from the Investor Partners at an average price of $7,382 per unit. As of September 30, 2011, the Managing General Partner owns 37.3% of the Partnership.

The Partnership expects continuing operations of its natural gas and crude oil properties until such time the Partnership's wells are depleted or become uneconomical to produce, at which time they may be sold or plugged, reclaimed and abandoned. The Partnership's maximum term of existence extends through December 31, 2056, unless dissolved by certain conditions stipulated within the Agreement which are unlikely to occur at this time, or by written consent of the Investor Partners owning a majority of outstanding units at that time.

In the Managing General Partner's opinion, the accompanying interim unaudited condensed financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary for a fair statement of the Partnership's financial statements for interim periods in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") and with the instructions to Form 10-Q and Article 8 of Regulation S-X of the Securities and Exchange Commission (“SEC”). Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in the audited financial statements have been condensed or omitted. The information presented in this quarterly report on Form 10-Q should be read in conjunction with the Partnership's audited financial statements and notes thereto included in the Partnership's 2010 Form 10-K. The Partnership's accounting policies are described in the Notes to Financial Statements in the Partnership's 2010 Form 10-K and updated, as necessary, in this Form 10-Q. The results of operations for the three and nine months ended September 30, 2011, and the cash flows for the same periods, are not necessarily indicative of the results to be expected for the full year or any other future period.

Certain reclassifications have been made to prior period financial statements to conform to the current year presentation, specifically related to the Partnership's discontinued operations. The reclassifications had no impact on previously reported cash flows, net income or Partners' equity. See Note 8, Divestitures and Discontinued Operations, for additional information regarding the Partnership's discontinued operations. Additionally, certain reclassifications have been made to correct the prior period disclosures to conform to the current year presentation, specifically related to the fair value level classification of certain derivative instruments. The reclassification had no impact on the Partnership's previously reported financial position, cash flows, net income or partners' equity. See Note 4, Fair Value Measurements and Disclosures, for additional information regarding the fair value classification of the Partnership's natural gas and crude oil derivative instruments.

-5-

ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 2011

(unaudited)

Note 2−Recent Accounting Standards

Recently Adopted Accounting Standards

Fair Value Measurements and Disclosures

In January 2010, the Financial Accounting Standards Board ("FASB") issued changes related to fair value measurements requiring gross presentation of activities within the Level 3 roll forward, whereby entities must present separately information about purchases, sales, issuances and settlements. These changes were effective for the Partnership's financial statements issued for annual reporting periods, and for interim reporting periods within the year, beginning after December 15, 2010. The adoption of this change did not have a material impact on the Partnership's financial statements.

Recently Issued Accounting Standards

Fair Value Measurement

On May 12, 2011, the FASB issued changes related to fair value measurement. The changes represent the converged guidance of the FASB and the International Accounting Standards Board ("IASB") (collectively the "Boards") on fair value measurement. Many of the changes eliminate unnecessary wording differences between International Financial Reporting Standards ("IFRS") and U.S. GAAP. The changes expand existing disclosure requirements for fair value measurements categorized in Level 3 by requiring (1) a quantitative disclosure of the unobservable inputs and assumptions used in the measurement, (2) a description of the valuation processes in place and (3) a narrative description of the sensitivity of the fair value to changes in unobservable inputs and the interrelationships between those inputs. In addition, the changes also require the categorization by level in the fair value hierarchy of items that are not measured at fair value in the statement of financial position whose fair value must be disclosed. These changes are to be applied prospectively and are effective for public entities during interim and annual periods beginning after December 15, 2011. Early application is not permitted. With the exception of the disclosure requirements, the adoption of these changes is not expected to have a significant impact on the Partnership's financial statements.

Note 3−Transactions with Managing General Partner and Affiliates

The Managing General Partner transacts business on behalf of the Partnership under the authority of the D&O Agreement. Revenues and other cash inflows received on behalf of the Partnership are distributed to the Partners net of (after deducting) corresponding operating costs and other cash outflows incurred on behalf of the Partnership. The fair value of the Partnership's portion of open derivative instruments is recorded on the condensed balance sheets under the captions “Due from Managing General Partner-derivatives,” in the case of net unrealized gains and “Due to Managing General Partner-derivatives,” in the case of net unrealized losses.

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



	September 30, 2011			December 31, 2010
Natural gas, NGLs and crude oil sales revenues collected from the Partnership's third-party customers	$	418,728		$	893,100
Commodity price risk management, realized gain	103,228			264,025
Other ⁽¹⁾	(197,532		)	(600,083		)
Total Due from Managing General Partner-other, net	$	324,424		$	557,042


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

-6-

ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 2011

(unaudited)

The following table presents Partnership transactions, excluding derivative transactions which are more fully detailed in Note 5, Derivative Financial Instruments, with the Managing General Partner and its affiliates for the three and nine months ended September 30, 2011 and 2010. “Well operations and maintenance” and “Gathering, compression and processing fees” are included in the “Natural gas, NGLs and crude oil production costs” line item on the condensed statements of operations.



	Three months ended September 30,				Nine months ended September 30,
	2011		2010		2011		2010
Well operations and maintenance	$	463,083	$	567,835	$	1,808,128	$	1,572,520
Gathering, compression and processing fees	60,208		69,586		179,368		271,407
Direct costs - general and administrative	46,140		35,402		133,860		119,072
Cash distributions ⁽¹⁾	333,799		580,562		2,925,944		2,567,778


(1)	Cash distributions include $2,757 and $23,919 during the three and nine months ended September 30, 2011, respectively, and $2,047 and $8,048 during the three and nine months ended September 30, 2010, respectively, related to equity cash distributions on Investor Partner units repurchased by PDC.

Note 4−Fair Value Measurements and Disclosures

Derivative Financial Instruments

Determination of fair value. Fair value accounting standards have established a fair value hierarchy that prioritizes the inputs used in applying a valuation methodology. 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. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. 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 their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as:

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

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

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

Derivative Financial Instruments. The Managing General Partner measures the fair value of its derivative instruments based on a pricing model that utilizes market-based inputs, including but not limited to the contractual price of the underlying position, current market prices, natural gas and crude oil forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of the Managing General Partner's credit standing on the fair value of derivative liabilities and the effect of the Managing General Partner's counterparties' credit standings on the fair value of derivative assets, both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position. The counterparties to the Partnership's derivative instruments are primarily financial institutions. The Managing General Partner validates the fair value measurement through (1) the review of counterparty statements and other supporting documentation, (2) the determination that the source of the inputs are valid, (3) the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and (4) monitoring changes in valuation methods and assumptions. While the Managing General Partner uses common industry practices to develop its valuation techniques, changes in the pricing methodologies or the underlying assumptions could result in significantly different fair values. While the Managing General Partner believes its valuation method is appropriate and consistent with those used by other market participants, the use of a different methodology, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value.

-7-

ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 2011

(unaudited)

The following table presents, for each hierarchy level, the Partnership's derivative assets and liabilities, both current and non-current portions, measured at fair value on a recurring basis.



	September 30, 2011						December 31, 2010 (a)
	Level 2 (b)		Level 3 (c)		Total		Level 2 (b)		Level 3 (c)		Total

Assets:
Commodity based derivatives	$	4,526,906	$	97,971	$	4,624,877	$	4,527,193	$	213,723	$	4,740,916
Total assets	4,526,906		97,971		4,624,877		4,527,193		213,723		4,740,916

Liabilities:
Commodity based derivatives	39,900		—		39,900		431,081		—		431,081
Basis protection derivative contracts	2,809,732		—		2,809,732		3,335,930		—		3,335,930
Total liabilities	2,849,632		—		2,849,632		3,767,011		—		3,767,011
Net asset	$	1,677,274	$	97,971	$	1,775,245	$	760,182	$	213,723	$	973,905

(a) The Partnership reclassified its NYMEX-based natural gas fixed-price swaps from Level 1 to Level 2 (decreasing the previously reported net asset in Level 1 by $4.5 million) and CIG-based basis swaps and crude oil fixed-price swaps from Level 3 to Level 2 (decreasing the previously reported net liability in Level 3 by $3.8 million). The amounts presented reflect these reclassifications and conform to current period presentation.

(b) Includes the Partnership's fixed-price swaps and basis swaps.

The following table presents a reconciliation of the Partnership's Level 3 fair value measurements.



	Nine months ended
	September 30, 2011			September 30, 2010 (1)
Fair value, net asset, beginning of period	$	213,723		$	440,768
Changes in fair value included in statement of operations line item:
Commodity price risk management gain, net	57,998			380,087
Settlements	(173,750		)	(443,605		)
Fair value, net asset, end of period	$	97,971		$	377,250

Change in unrealized gain (loss) relating to assets (liabilities) still held as of
September 30, 2011 and 2010, respectively, included in statement of operations line item:
Commodity price risk management gain, net	$	33,646		$	336,579

(1) The Partnership reclassified its CIG-based basis swaps and crude oil fixed-price swaps from Level 3 to Level 2 (decreasing the previously reported net liability at the beginning of the period by $3.3 million). The amounts presented reflect these reclassifications and conform to current period presentation.

See Note 5, Derivative Financial Instruments, for additional disclosure related to the Partnership's derivative financial instruments.

Non-Derivative Financial Assets and Liabilities

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

-8-

ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 2011

(unaudited)

Note 5−Derivative Financial Instruments

As of September 30, 2011, the Partnership had derivative instruments in place for a portion of its anticipated natural gas production through 2013 for a total of 1,843,767 MMbtu and its anticipated crude oil production through December of 2011 for a total of 4,871 Bbl.

The following table presents the location and fair value amounts of the Partnership's derivative instruments on the accompanying condensed balance sheets. These derivative instruments were comprised of commodity collars, commodity fixed-price swaps and basis swaps.



			Fair Value
			September 30,		December 31,
Derivative instruments not designated as hedge⁽¹⁾:		Balance Sheet Line Item	2011		2010
Derivative Assets:	Current
	Commodity contracts	Due from Managing General Partner-derivatives	$	2,417,825	$	1,878,527
	Non Current
	Commodity contracts	Due from Managing General Partner-derivatives	2,207,052		2,862,389
Total Derivative Assets			$	4,624,877	$	4,740,916

Derivative Liabilities:	Current
	Commodity contracts	Due to Managing General Partner-derivatives	$	39,900	$	431,081
	Basis protection contracts	Due to Managing General Partner-derivatives	1,360,819		1,163,209
	Non Current
	Basis protection contracts	Due to Managing General Partner-derivatives	1,448,913		2,172,721
Total Derivative Liabilities			$	2,849,632	$	3,767,011

⁽¹⁾As of September 30, 2011 and December 31, 2010, none of the Partnership's derivative instruments were designated as hedges.

-9-

ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 2011

(unaudited)

The following tables present the impact of the Partnership's derivative instruments on the Partnership's accompanying condensed statements of operations.



	Three months ended September 30,
	2011							2010
Statement of operations line item:	Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains For the Current Period		Total		Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains For the Current Period		Total
Commodity price risk management gain, net
Realized gains	$	74,643		$	56,096	$	130,739	$	112,014		$	123,862	$	235,876
Unrealized gains (losses)	(74,643		)	817,532		742,889		(112,014		)	1,652,801		1,540,787
Total commodity price risk management gain, net	$	—		$	873,628	$	873,628	$	—		$	1,776,663	$	1,776,663

	Nine months ended September 30,
	2011							2010
Statement of operations line item:	Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains For the Current Period		Total		Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains For the Current Period		Total
Commodity price risk management gain, net
Realized gains	$	276,397		$	19,872	$	296,269	$	383,673		$	1,165,219	$	1,548,892
Unrealized gains (losses)	(276,397		)	1,077,737		801,340		(383,673		)	4,057,884		3,674,211
Total commodity price risk management gain, net	$	—		$	1,097,609	$	1,097,609	$	—		$	5,223,103	$	5,223,103

Concentration of Credit Risk. The Managing General Partner makes use of over-the-counter derivative instruments that enable the Partnership to manage a portion of its exposure to price volatility from producing natural gas and crude oil. These arrangements expose the Partnership to the credit risk of nonperformance by the counterparties. The Managing General Partner primarily uses financial institutions, who are also major lenders in the Managing General Partner's credit facility agreement, as counterparties to its derivative contracts. To date, the Managing General Partner has had no counterparty default losses. The Managing General Partner has evaluated the credit risk of the Partnership's derivative assets from counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on this evaluation, the Managing General Partner has determined that the impact of the nonperformance of the counterparties on the fair value of the Partnership's derivative instruments was not significant.

-10-

ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 2011

(unaudited)

Note 6−Commitments and Contingencies

Legal Proceedings

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

Environmental

Due to the nature of the natural gas and crude oil industry, the Partnership is exposed to environmental risks. The Managing General Partner has various policies and procedures in place to avoid environmental contamination and mitigate the risks from environmental contamination. The Managing General Partner conducts periodic reviews to identify changes in the Partnership's environmental risk profile. Liabilities are accrued when environmental remediation efforts are probable and the costs can be reasonably estimated. During the three months ended September 30, 2011, there were no new material environmental remediation projects identified by the Managing General Partner for the Partnership. As of September 30, 2011, the Partnership had accrued environmental remediation liabilities for three of the Partnership's well pads involving nine wells in the amount of approximately $28,000, which is included in line item captioned “Accounts payable and accrued expenses” on the condensed balance sheet. As of December 31, 2010, the Partnership had accrued environmental remediation liabilities for three of the Partnership's well pads involving 10 wells in the amount of approximately $113,000, which is included in line item captioned “Accounts payable and accrued expenses” on the condensed balance sheet. The Managing General Partner is not currently aware of any environmental claims existing as of September 30, 2011, which have not been provided for or would otherwise have a material impact on the Partnership's condensed financial statements. However, there can be no assurance that current regulatory requirements will not change or unknown past non-compliance with environmental laws will not be discovered on the Partnership's properties.

Note 7−Asset Retirement Obligations

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



	September 30, 2011

Balance at December 31, 2010 (1)	$	1,098,625
Obligations discharged with disposal of properties and asset retirements	(194,135		)
Accretion expense	38,908
Balance at September 30, 2011	$	943,398

(1)Includes $0.2 million as of December 31, 2010, related to assets held for sale.

-11-

ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 2011

(unaudited)

Note 8-Divestitures and Discontinued Operations

During the fourth quarter of 2010, the Managing General Partner developed a plan to divest Partnership's North Dakota assets. The plan included 100% of the Partnership's North Dakota assets, consisting of producing wells and related facilities. The plan received the Managing General Partner's Board of Directors' approval and, in December 2010, the Managing General Partner effected a letter of intent with an unrelated third party. Following the sale to the unrelated party, the Partnership did not have significant continuing involvement in the operations of or cash flows from these assets; accordingly, the North Dakota assets were reclassified as held for sale as of December 31, 2010, and the results of operations related to those assets have been separately reported as discontinued operations in the accompanying financial statements for all periods presented. In February 2011, the Managing General Partner executed a purchase and sale agreement on behalf of the Partnership and subsequently closed with the same unrelated party. The Partnership received proceeds from the sale of $5.7 million for these assets resulting in a gain on sale of $3.5 million.

The table below presents statement of operations data related to the Partnership's discontinued operations of the Partnership's North Dakota assets. While the reclassification of revenues and expenses related to discontinued operations for the prior periods had no impact upon previously reported net earnings, the statement of operations data present the revenues and expenses that were reclassified from the specified statement of operations line items to discontinued operations. There was no activity recorded for discontinued operations for the three months ended September 30, 2011.



	Three Months Ended September 30,		Nine Months Ended September 30,
Statement of Operations - Discontinued Operations	2010		2011		2010

Revenues:
Natural gas, NGLs and crude oil sales	$	383,345	$	204,415	$	1,170,801
Total revenues	383,345		204,415		1,170,801

Operating costs and expenses:
Natural gas, NGLs and crude oil production costs	112,645		56,238		246,962
Depreciation, depletion and amortization	100,490		—		293,403
Total operating costs and expenses	213,135		56,238		540,365

Net income from discontinued operations	170,210		148,177		630,436

Gain on sale of natural gas and crude oil properties	—		3,515,554		—

Income from discontinued operations	$	170,210	$	3,663,731	$	630,436

-12-

ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 2011

(unaudited)

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Partnership Overview

Rockies Region 2006 Limited Partnership engages in the development, production and sale of natural gas, NGLs and crude oil. The Partnership began natural gas and crude oil operations in September 2006 and operates 86 gross (85.1 net) productive wells located in the Rocky Mountain Region in the state of Colorado. The Partnership drilled four additional wells determined to be dry holes; one developmental dry hole and three exploratory dry holes in the Wattenberg Field in Colorado. The Partnership drilled five (4.5 net) producing wells in North Dakota and two exploratory dry holes in North Dakota. In February 2011, the Partnership sold the Partnership's North Dakota assets. The Managing General Partner markets the Partnership's natural gas and crude oil production to commercial end users, interstate or intrastate pipelines, local utilities or oil companies, primarily under market sensitive contracts in which the price of natural gas, NGLs and crude oil sold varies as a result of market forces. PDC does not charge a separate fee for the marketing of the natural gas, NGLs and crude oil because these services are covered by the monthly well operating charge. PDC, on behalf of the Partnership in accordance with the D&O Agreement, is authorized to enter into multi-year fixed price contracts or utilize derivatives, including collars, swaps or basis protection swaps, in order to offset some or all of the commodity price variability for particular periods of time. Seasonal factors, such as effects of weather on prices received and costs incurred, and availability of pipeline capacity, owned by PDC or other third parties, may impact the Partnership's results. In addition, both sales volumes and prices tend to be affected by demand factors with a seasonal component.

Recent Developments

PDC Sponsored Drilling Program Acquisition Plan

PDC, the managing general partner of various public limited partnerships, has disclosed its intention to pursue, which began in the fall of 2010 and extends through 2012, the acquisition of the limited partnership units (the “Acquisition Plan”) held by Investor Partners of the particular partnership other than those held by PDC or its affiliates (“non-affiliated investor partners”), in certain limited partnerships that PDC had previously sponsored, including this Partnership. For additional information regarding PDC's intention to pursue acquisitions of PDC sponsored partnerships, refer to prior disclosure included in PDC's filings made with the SEC. However, such information shall not, by reason of this reference, be deemed to be incorporated by reference in, or otherwise be deemed to be part of, this report. Under the Acquisition Plan, any existing or future merger offer will be subject to the terms and conditions of the related merger agreement, and such agreement will likely contemplate the partnership being merged with and into a wholly-owned subsidiary of PDC. Each such merger will also be subject to, among other things, PDC having sufficient available capital, the economics of the merger and the approval by a majority of the limited partnership units held by the non-affiliated investor partners of such limited partnership. Consummation of any proposed merger of a limited partnership under the Acquisition Plan will result in the termination of the existence of that partnership and each non-affiliated investor partner will receive the right to receive a cash payment for their limited partnership units in that partnership and will no longer participate in that partnership's future earnings or any further economic benefit.

In June 2011, PDC acquired three affiliated partnerships: PDC 2005-A Limited Partnership, PDC 2005-B Limited Partnership and Rockies Region Private Limited Partnership. PDC purchased these partnerships for the aggregate amount of $43.0 million.

In November 2011, PDC acquired five additional affiliated partnerships: PDC 2003-A Limited Partnership, PDC 2003-B Limited Partnership, PDC 2003-C Limited Partnership, PDC 2003-D Limited Partnership and the PDC 2002-D Limited Partnership, for the aggregate amount of $29.5 million.

The feasibility and timing of any future cash purchase offer by PDC to any additional partnership, including this Partnership, depends on that partnership's suitability in meeting a set of criteria that includes, but is not limited to, the following: age and productive-life stage characteristics of the partnership's well inventory; favorability of economics for Wattenberg Field well refracturing; and SEC reporting compliance status and timing associated with gaining all necessary regulatory approvals required for a merger and repurchase offer. There is no assurance that any potential proposed repurchase offer to any other of PDC's various public limited partnerships, including this Partnership, will occur.

-13-

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Well Refracturing Plan

The Managing General Partner has prepared a plan for the Partnership's Wattenberg Field wells which may provide for additional reserve development of natural gas, NGLs and crude oil production (the “Well Refracturing Plan”). The Well Refracturing Plan consists of the Partnership's refracturing of wells currently producing in the Codell formation. Under the Well Refracturing Plan, the Partnership plans to initiate refracturing activities during 2012. Refracturing activities consist of a second hydraulic fracturing treatment in a current production zone, all within an existing well bore.

Refracturing of Wattenberg Field wells, which may provide for additional reserve development and production, generally occurs five to ten years after initial well drilling so that well resources are optimally utilized. This refracturing would be expected to occur based on a favorable general economic environment and commodity price structure. The Managing General Partner has the authority to determine whether to refracture the individual wells and to determine the timing of any refracturing activity. The timing of the refracturing can be affected by the desire to optimize the economic return by refracturing the wells when commodity prices are at levels to obtain the highest rate of return to the Partnership. On average, the production resulting from PDC's Codell refracturings have been at modeled economics; however, all refracturings have not been economically successful and similar future refracturing activities may not be economically successful. If the refracturing work is performed, PDC will charge the Partnership for the direct costs of refracturing, and the Investor Partners and the Managing General Partner will each pay their proportionate share of costs based on the ownership sharing ratios of the Partnership from funds retained by the Managing General Partner from cash available for distributions. The Managing General Partner considers the cash available for distributions to be the Partnership's net cash flows provided by operating activities less any net cash used in capital activities.

The Limited Partnership Agreement (the “Agreement”) permits the Partnership to borrow funds or receive advances, from the Managing General Partner, its affiliates or unaffiliated persons, for Partnership activities. At this time, the Managing General Partner does not anticipate electing to fund the initial Well Refracturing Plan well refracturing, nor any subsequent refracturings, through bank borrowing. In the event that the Partnership's Codell formation refracturing activities are funded in part through borrowing, potential cash available for distributions derived from production increases provided by the further development of the Partnership's Wattenberg Field wells may not be sufficient to repay the Partnership's borrowing financial obligations, which will include principal and interest. Borrowings, if any, will be non-recourse to the Investor Partners; accordingly, the Partnership, not the Investor Partners, will be responsible for loan repayment. However, any bank borrowings may be collateralized by the Partnership's assets.

During the fourth quarter of 2010, the Managing General Partner began a program for its affiliated partnerships to begin accumulating cash from cash flows from operating activities to pay for future refracturing costs. This program will materially reduce, up to 100%, cash available for distributions of the partnerships for a period of time not to exceed five years.

Current estimated costs for these well refracturings are between $175,000 and $240,000 per activity. As of September 30, 2011, this Partnership had scheduled to complete 62 refracturing opportunities. Total withholding for these activities from the Partnership's cash available for distributions is estimated to be between $10.9 million and $14.9 million. The Managing General Partner will continually evaluate the timing of commencing these refracturing activities based on engineering data and a favorable commodity price environment in order to maximize the financial benefit of the additional well development. During the three months ended September 30, 2011, $50,000 was withheld from the Partnership's cash distributions pursuant to the Well Refracturing Plan. Cumulatively, $1,670,000 has been withheld from Partnership distributions through October 31, 2011, which includes $1,000,000 that was withheld from the proceeds of the sale of the Partnership's North Dakota assets during April 2011, and resides in the Partnership's bank account.

If any or all of the Partnership's Wattenberg wells are not refractured, the Partnership will experience a reduction in proved reserves currently assigned to these wells. Both the number and timing of the refracturing activities will be based on the availability of cash withheld from Partnership distributions. The Managing General Partner believes that, based on projected refracturing costs and projected cash withholding, all scheduled Partnership refracturing activity will be completed within a five year period. Any funds not used for refracturing or other operational needs will be distributed to the Managing General Partner and Investor Partners based on their proportional ownership interest.

Implementation of the Well Refracturing Plan has and will continue to reduce or eliminate Partnership distributions to the Managing General Partner and Investor Partners while the work is being conducted and paid for through the Partnership's funds. Depending upon the level of withholding and the results of operations, it is possible that the Managing General Partner and Investor Partners could have taxable income from the Partnership without any corresponding distributions in future years. Non-affiliated investor partners are urged to consult a tax advisor to determine all of the relevant federal, state and local tax consequences of the Well Refracturing Plan. The above discussion is not intended as a substitute for careful tax planning, and non-affiliated investor partners should depend upon the advice of their own tax advisors concerning the effects of the

-14-

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Well Refracturing Plan.

Partnership Operating Results Overview

Natural gas, NGLs and crude oil sales decreased 28%, or $1.9 million, for the first nine months of 2011 compared to the first nine months of 2010, while sales volumes declined 25% period-to-period. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $5.25 for the current year period compared to $5.42 for the same period a year ago. Realized derivative gains from natural gas and crude oil sales contributed an additional $0.31 per Mcfe, or $0.3 million, to the first nine months of 2011 total revenues compared to an additional $1.19, or $1.5 million, to the first nine months of 2010. Comparatively, the total realized price per Mcfe, consisting of the average sales price and realized derivative gains, decreased to $5.56 for the current year nine months from $6.61 for the same prior year period.

In February 2011, the Partnership's North Dakota assets were sold for total proceeds to the Partnership of $5.7 million resulting in a gain of $3.5 million. The operating results of the North Dakota assets for the three month period ended September 30, 2010 and for the nine month periods ended September 30, 2011 and 2010 are classified as discontinued operations. There was no activity recorded for discontinued operations for the three months ended September 30, 2011.

-15-

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Results of Operations

Summary Operating Results

The following table presents selected information regarding the Partnership’s results of continuing operations.



	Three months ended September 30,							Nine months ended September 30,
	2011			2010		Change		2011			2010		Change
Number of gross producing wells (end of period)	86			86		—		86			86		—

Production⁽¹⁾
Natural gas (Mcf)	232,559			297,964		(22	)%	753,534			959,077		(21	)%
NGLs (Bbl)	3,455			3,995		(14	)%	9,503			13,212		(28	)%
Crude oil (Bbl)	8,583			12,615		(32	)%	27,107			43,777		(38	)%
Natural gas equivalents (Mcfe)⁽²⁾	304,787			397,624		(23	)%	973,194			1,301,011		(25	)%
Average Mcfe per day	3,313			4,322		(23	)%	3,565			4,766		(25	)%

Natural Gas, NGLs and Crude Oil Sales
Natural gas	$	735,937		$	937,897	(22	)%	$	2,371,210		$	3,528,482	(33	)%
NGLs	126,026			96,574		30	%	360,054			402,172		(10	)%
Crude oil	703,743			878,516		(20	)%	2,381,467			3,123,458		(24	)%
Total natural gas, NGLs and crude oil sales	$	1,565,706		$	1,912,987	(18	)%	$	5,112,731		$	7,054,112	(28	)%

Realized Gain (Loss) on Derivatives, net
Natural gas	$	224,033		$	52,712	*		$	659,250		$	1,052,288	(37	)%
Crude oil	(93,294		)	183,164		(151	)%	(362,981		)	496,604		(173	)%
Total realized gain on derivatives, net	$	130,739		$	235,876	(45	)%	$	296,269		$	1,548,892	(81	)%

Average Selling Price (excluding realized gain (loss) on derivatives)
Natural gas (per Mcf)	$	3.16		$	3.15	1	%	$	3.15		$	3.68	(14	)%
NGLs (per Bbl)	36.48			24.17		51	%	37.89			30.44		24	%
Crude oil (per Bbl)	81.99			69.64		18	%	87.85			71.35		23	%
Natural gas equivalents (per Mcfe)	5.14			4.81		7	%	5.25			5.42		(3	)%

Average Selling Price (including realized gain (loss) on derivatives)
Natural gas (per Mcf)	$	4.13		$	3.32	24	%	$	4.02		$	4.78	(16	)%
NGLs (per Bbl)	36.48			24.17		51	%	37.89			30.44		24	%
Crude oil (per Bbl)	71.12			84.16		(15	)%	74.46			82.69		(10	)%
Natural gas equivalents (per Mcfe)	5.57			5.40		3	%	5.56			6.61		(16	)%

Average cost per Mcfe
Natural gas, NGLs and crude oil production cost⁽³⁾	$	2.01		$	1.89	6	%	$	2.32		$	1.71	36	%
Depreciation, depletion and amortization	$	2.32		$	3.86	(40	)%	$	2.32		$	3.88	(40	)%

Operating costs and expenses:
Direct costs - general and administrative	$	46,140		$	35,402	30	%	$	133,860		$	119,072	12	%
Depreciation, depletion and amortization	$	707,030		$	1,535,375	(54	)%	$	2,254,253		$	5,042,104	(55	)%

Cash distributions	$	894,708		$	1,563,554	(43	)%	$	7,843,309		$	6,918,188	13	%

*Percentage change not meaningful, equal to or greater than 250% or not calculable.

Amounts may not calculate due to rounding.

-16-

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

_______________

⁽¹⁾ Production is net and determined by multiplying the gross production volume of properties in which the Partnership has an interest by the average percentage of the leasehold or other property interest the Partnership owns.

⁽²⁾ Six Mcf of natural gas equals one Bbl of crude oil or NGL.

⁽³⁾ Represent natural gas, NGLs and crude oil operating expenses which include production taxes.

Definitions used throughout Management’s Discussion and Analysis of Financial Condition and Results of Operations:


•	Bbl – One barrel or 42 U.S. gallons liquid volume


•	MBbl – One thousand barrels


•	Mcf – One thousand cubic feet


•	MMcf – One million cubic feet


•	Mcfe – One thousand cubic feet of natural gas equivalents


•	MMcfe – One million cubic feet of natural gas equivalents


•	MMbtu – One million British Thermal Units

Natural Gas, NGLs and Crude Oil Sales

Nine months ended September 30, 2011 as compared to nine months ended September 30, 2010

For the nine months ended September 30, 2011 compared to the same period in 2010, natural gas, NGLs and crude oil sales volume, on an energy equivalency-basis, decreased 25% due to normal production declines for this stage in the wells' production life cycle.

The $1.9 million, or 28%, decrease in sales for the 2011 nine month period as compared to the prior year period was primarily a reflection of sales volume decreases of 25% and a decline in average sales prices of 3%. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $5.25 for the current year nine month period compared to $5.42 for the same period a year ago.

Natural gas, NGLs and crude oil sales decreased by 33%, 10% and 24%, respectively. The Partnership's natural gas sales decrease resulted from lower Partnership natural gas production volumes of 21% and from decreased average commodity price per Mcf of 14%. The decrease in NGLs sales was due to a decrease of 28% in NGLs production volumes, partially offset by increased average commodity price per Bbl of 24%. The crude oil sales decrease was due primarily to sales volume decreases of 38%, partially offset by the rise in average commodity price per Bbl of 23% during the current nine month period.

Three months ended September 30, 2011 as compared to three months ended September 30, 2010

For the three months ended September 30, 2011 compared to the same period in 2010, natural gas, NGLs and crude oil sales volume, on an energy equivalency-basis, decreased 23% due to normal production declines for this stage in the wells' production life cycle.

The $0.3 million, or 18%, decrease in sales for the 2011 three month period as compared to the prior year period was primarily a reflection of sales volume decreases of 23% partially offset by an increase in average sales prices of 7%. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $5.14 for the current year three month period compared to $4.81 for the same period a year ago.

Natural gas and crude oil sales decreased by 22% and 20%, respectively, while NGLs sales increased by 30%. The Partnership's natural gas sales decrease resulted from lower Partnership natural gas production volumes of 22%, partially offset by increased average commodity price per Mcf of 1%. The crude oil sales decrease was due primarily to sales volume decreases of 32%, partially offset by the rise in average commodity price per Bbl of 18% during the current three month period. The increase in NGLs sales was due to an increase of 51% in average commodity price per Bbl, partially offset by a decrease of 14% in NGLs production volumes.

-17-

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Commodity Price Risk Management, Net

The Partnership uses various derivative instruments to manage fluctuations in natural gas and crude oil prices. The Partnership has in place a variety of collars, fixed-price swaps and basis swaps on a portion of the Partnership's estimated natural gas and crude oil production. The Partnership sells its natural gas and crude oil at similar prices to the indices inherent in the Partnership's derivative instruments. As a result, for the volumes underlying the Partnership's derivative positions, the Partnership ultimately realizes a price related to its collars of no less than the floor and no more than the ceiling and, for the Partnership's commodity swaps, the Partnership ultimately realizes the fixed price related to its swaps.

Commodity price risk management, net, includes realized gains and losses and unrealized mark-to-market changes in the fair value of the derivative instruments related to the Partnership's natural gas and crude oil production. See Note 4, Fair Value Measurements and Disclosures and Note 5, Derivative Financial Instruments, to the Partnership's unaudited condensed financial statements included in this report for additional details of the Partnership's derivative financial instruments.

The following table presents the realized and unrealized derivative gains and losses included in commodity price risk management gain, net.



	Three months ended September 30,						Nine months ended September 30,
	2011			2010			2011			2010
Commodity price risk management gain, net:
Realized gains (losses)
Natural gas	$	224,033		$	52,712		$	659,250		$	1,052,288
Crude oil	(93,294		)	183,164			(362,981		)	496,604
Total realized gains, net	130,739			235,876			296,269			1,548,892

Unrealized gains
Reclassification of realized gains included in
prior periods unrealized	(74,643		)	(112,014		)	(276,397		)	(383,673		)
Unrealized gains for the period	817,532			1,652,801			1,077,737			4,057,884
Total unrealized gains, net	742,889			1,540,787			801,340			3,674,211
Total commodity price risk management gain, net	$	873,628		$	1,776,663		$	1,097,609		$	5,223,103

Nine months ended September 30, 2011 as compared to nine months ended September 30, 2010

Realized gains recognized in the nine months ended September 30, 2011 were primarily the result of lower natural gas spot prices at settlement compared to the respective strike price of the Partnership's natural gas derivative positions. Realized gains on natural gas settlements were $1.6 million for the nine months ended September 30, 2011. These gains were offset in part by a $0.9 million loss on the Partnership's Colorado Interstate Gas (“CIG”) basis protection swaps as the negative basis differential between NYMEX and CIG was narrower than the strike price of the basis positions. The Partnership also realized a $0.4 million loss on its crude oil positions due to higher spot prices at settlement compared to the respective strike price. Unrealized gains during the nine months ended September 30, 2011 were primarily related to the shifts in the forward curves and their impact on the fair value of the Partnership's open positions. The shifts downward in the natural gas curves resulted in an unrealized gain of $1.3 million and the shift downward in the crude oil curve resulted in an unrealized gain of $0.1 million during the nine months ended September 30, 2011. These unrealized gains were partially offset by unrealized losses of $0.3 million on the Partnership's CIG basis protection swaps as the forward basis differential between the NYMEX and CIG had continued to narrow.

The realized derivative gains for the 2010 nine month period were $1.5 million. These realized gains were primarily a result of lower natural gas and crude oil spot prices at settlement compared to the respective strike price, offset in part by realized losses due to the basis differential between NYMEX and CIG being narrower than the strike price of the derivative position. For the 2010 nine month period, realized gains related to natural gas and crude oil derivatives were $2.2 million and realized losses on the Partnership’s basis position were $0.7 million. Unrealized gains for the 2010 nine month period were $4.1 million due primarily to a downward shift in the natural gas and crude oil forward curves, offset by unrealized losses due to the basis differential between NYMEX and CIG being narrower than the strike price of the derivative position. Unrealized gains on the Partnership’s commodity positions for the 2010 nine month period were $4.4 million offset in part by unrealized losses on the Partnership's basis position of $0.3 million.

-18-

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Three months ended September 30, 2011 as compared to three months ended September 30, 2010

Realized gains recognized in the three months ended September 30, 2011 were primarily the result of lower natural gas spot prices at settlement compared to the respective strike price of the Partnership's natural gas derivative positions. Realized gains on natural gas settlements were $0.6 million for the three months ended September 30, 2011. These gains were offset in part by a $0.4 million loss on the Partnership's CIG basis protection swaps as the negative basis differential between NYMEX and CIG was narrower than the strike price of the basis positions. The Partnership also realized a $0.1 million loss on its crude oil positions due to higher spot prices at settlement compared to the respective strike price. Unrealized gains during the three months ended September 30, 2011 are primarily related to the shifts in the forward curves and their impact on the fair value of the Partnership's open positions. The shifts downward in the natural gas curves resulted in an unrealized gain of $0.9 million and the shift downward in the crude oil curve resulted in an unrealized gain of $0.1 million during the three months ended September 30, 2011. These unrealized gains were partially offset by unrealized losses of $0.2 million on the Partnership's CIG basis protection swaps as the forward basis differential between the NYMEX and CIG had continued to narrow.

The realized derivative gains for the 2010 third quarter were $0.2 million. These realized gains were a result of lower natural gas and crude oil spot prices at settlement compared to the respective strike price, offset in part by realized losses due to the basis differential between NYMEX and CIG being narrower than the strike price of the derivative position. For the quarter, realized gains related to natural gas and crude oil derivatives were $0.5 million and realized losses on the Partnership's basis position were $0.3 million. For the 2010 quarter, the unrealized gains of $1.7 million were primarily related to the natural gas positions, as the forward strip price shifted downward during the quarter. These unrealized gains were partially offset by unrealized losses due to the narrowing of the NYMEX-CIG basis differential. Unrealized gains on the Partnership’s commodity positions for the 2010 third quarter were $1.8 million partially offset by unrealized losses on the Partnership's basis position of $0.2 million.

The following table presents the Partnership's derivative positions in effect as of September 30, 2011.



	Collars					Fixed-Price Swaps			CIG Basis Protection Swaps
Commodity/ Index	Quantity (Gas-MMBtu⁽¹⁾)	Weighted Average Contract Price				Quantity (Gas-MMBtu⁽¹⁾ Crude Oil-Bbls)	Weighted Average Contract Price		Quantity (Gas-MMBtu⁽¹⁾)	Weighted Average Contract Price			Fair Value at September 30, 2011⁽²⁾
		Floors		Ceilings

Natural Gas
NYMEX
10/01 - 12/31/2011	—	$	—	$	—	230,090	$	6.78	230,090	$	(1.88	)	$	297,327
01/01 - 03/31/2012	18,311	6.00		8.27		202,183	6.98		220,494	(1.88		)	247,447
04/01 - 06/30/2012	9,800	6.00		8.27		204,936	6.98		214,736	(1.88		)	270,409
07/01 - 09/30/2012	13,116	6.00		8.27		197,761	6.98		210,877	(1.88		)	241,823
10/01 - 12/31/2012	14,216	6.00		8.27		190,285	6.98		204,501	(1.88		)	174,266
2013	—	—		—		763,069	7.12		763,069	(1.88		)	583,873
Total Natural Gas	55,443					1,788,324			1,843,767				1,815,145

Crude Oil
NYMEX
10/01 - 12/31/2011	—	—		—		4,871	70.75		—	—			(39,900		)
Total Crude Oil	—					4,871			—				(39,900		)

Total Natural Gas and Crude Oil													$	1,775,245

⁽¹⁾A standard unit of measure for natural gas (one MMBtu equals one Mcf).

⁽²⁾Approximately 2% of the fair value of the Partnership's derivative assets and none of the Partnership's derivative liabilities were measured using significant unobservable inputs (Level 3); see Note 4, Fair Value Measurements and Disclosures, to the accompanying unaudited condensed financial statements included in this report.

-19-

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Natural Gas, NGLs and Crude Oil Production Costs

Generally, natural gas, NGLs and crude oil production costs vary with changes in total natural gas, NGLs and crude oil sales and production volumes. Production taxes are estimates by the Managing General Partner based on tax rates determined using published information. These estimates are subject to revision based on actual amounts determined during future filings by the Managing General Partner with the taxing authorities. Production taxes vary directly with total natural gas, NGLs and crude oil sales. Transportation costs vary directly with production volumes. Fixed monthly well operating costs increase on a per unit basis as production decreases per the historical decline curve. In addition, general oil field services and all other costs vary and can fluctuate based on services required but are expected to increase as wells age and require more extensive repair and maintenance. These costs include water hauling and disposal, equipment repairs and maintenance, snow removal, environmental compliance and remediation, and service rig workovers.

Nine months ended September 30, 2011 as compared to nine months ended September 30, 2010

Production costs per Mcfe increased to $2.32 during the current period compared to $1.71 for the prior year period due to the effect of higher per well related expenditures, partially offset by lower per volume related natural gas, NGLs and crude oil production costs. Current period production costs included $0.5 million in tubing repairs at two of the Partnership's Grand Valley Field wells. The prior year period includes environmental remediation costs of approximately $0.5 million.

Three months ended September 30, 2011 as compared to three months ended September 30, 2010

Production costs per Mcfe increased to $2.01 during the current period compared to $1.89 for the prior year period due to the effect of volume decreases spread over fixed well costs. During the third quarter of 2010, higher lease operating expenses were the result of $0.2 million for well workovers and environmental remediation projects.

Direct Costs −General and Administrative

Nine months ended September 30, 2011 as compared to nine months ended September 30, 2010

Direct costs - general and administrative consist primarily of professional fees for financial statement audits, income tax return preparation, independent engineer's reserve reports and legal matters. Direct costs increased by approximately $15,000, or 12%, during the nine months ended September 30, 2011, compared to the same period in 2010, principally due to increased fees for professional services.

Three months ended September 30, 2011 as compared to three months ended September 30, 2010

Direct costs increased by approximately $11,000, or 30%, during the three months ended September 30, 2011, compared to the same period in 2010, principally due to increased fees for professional services.

Depreciation, Depletion and Amortization (DD&A)

Nine months ended September 30, 2011 as compared to nine months ended September 30, 2010

DD&A expense per Mcfe decreased to $2.32 for the 2011 nine month period, compared to $3.88 during the same period in 2010. The decrease of $1.56 per Mcfe for the 2011 period compared to the 2010 period was primarily due to a decrease of $2.09 as a result of the 2010 impairment of the Partnership's Grand Valley Field. This decrease was partially offset by a net increase of $0.53 resulting from a downward revision in the Partnership's proved developed producing natural gas, NGLs and crude oil reserves in the Grand Valley Field partially offset by the upward revision in the Partnership's proved developed producing natural gas, NGLs and crude oil reserves in the Wattenberg Field as of December 31, 2010. The decrease in production and the decreased DD&A expense rate resulted in an overall decreased DD&A expense of $2.8 million for the 2011 nine month period compared to the same 2010 period.

-20-

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Three months ended September 30, 2011 as compared to three months ended September 30, 2010

DD&A expense per Mcfe decreased to $2.32 for the 2011 three month period, compared to $3.86 during the same period in 2010. The decrease of $1.54 per Mcfe for the 2011 period compared to the 2010 period was primarily due to a decrease of $2.08 as a result of the 2010 impairment of the Partnership's Grand Valley Field. This decrease was partially offset by a net increase of $0.54 resulting from a downward revision in the Partnership's proved developed producing natural gas, NGLs and crude oil reserves in the Grand Valley Field partially offset by the upward revision in the Partnership's proved developed producing natural gas, NGLs and crude oil reserves in the Wattenberg Field as of December 31, 2010. The decrease in production and the decreased DD&A expense rate resulted in an overall decreased DD&A expense of $0.8 million for the 2011 three month period compared to the same 2010 period.

Discontinued Operations

See Note 8, Divestitures and Discontinued Operations, to the accompanying unaudited condensed financial statements included in this report for additional information regarding the divestiture of the North Dakota assets.

In December 2010, the Managing General Partner effected a letter of intent with an unrelated third party, which provided for the sale of 100% of the Partnership's North Dakota assets. In February 2011, the Managing General Partner executed a purchase and sale agreement and subsequently closed with the same unrelated third party. Proceeds from the sale were $5.7 million resulting in a gain of $3.5 million. The Partnership had $0.2 million in revenues and $0.1 million in income from the North Dakota assets during the nine months ended September 30, 2011. The Partnership had $1.2 million in revenues and $0.6 million in income from the North Dakota assets during the nine months ended September 30, 2010.

-21-

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Financial Condition, Liquidity and Capital Resources

The Partnership's primary sources of cash for the nine months ended September 30, 2011 were from funds provided by operating activities which include the sale of natural gas, NGLs and crude oil production, the realized gains from the Partnership's derivative positions and additionally from the $5.7 million in proceeds from the divestiture of the Partnership's North Dakota assets. These sources of cash were primarily used to fund the Partnership's operating costs, general and administrative activities and provided monthly distributions to the Investor Partners and PDC, the Managing General Partner. During the quarter ended September 30, 2011, the Managing General Partner withheld $50,000 from the Partnership's regular cash distributions pursuant to the Well Refracturing Plan. Through October 31, 2011, $1,670,000 has been withheld from Partnership distributions to fund this plan, including $1,000,000 of the proceeds received from the North Dakota asset sale. These and subsequent withholdings will provide the funding for planned Wattenberg Field well refracturing costs to be incurred during 2012. For additional information, see Item 2, Management's Discussion and Analysis of Financial Condition and Results of Operations, Recent Developments-Well Refracturing Plan.

Fluctuations in the Partnership's operating cash flows are substantially driven by changes in commodity prices, in production volumes and in realized gains and losses from commodity positions. Commodity prices have historically been volatile and the Managing General Partner attempts to manage this volatility through derivatives. Therefore, the primary source of the Partnership's cash flow from operations becomes the net activity between the Partnership's natural gas, NGLs and crude oil sales and realized natural gas and crude oil derivative gains and losses. However, the Partnership does not engage in speculative positions, nor does the Partnership hold derivative instruments for 100% of the Partnership's expected future production from producing wells and therefore may still experience significant fluctuations in cash flows from operations. As of September 30, 2011, the Partnership had natural gas and crude oil derivative positions in place covering 85% of the expected natural gas production and 45% of expected crude oil production for the remainder of 2011, at an average price of $4.90 per Mcf and $70.75 per Bbl, respectively. The Partnership's current derivative position average prices have declined from the significantly higher average commodity contract strike price levels in effect during the first quarter of 2010 comparative period which were the result of contracts entered into during the high 2008 commodity price market. See Results of Operations for further discussion of the impact of prices and volumes on sales from operations and the impact of derivative activities on the Partnership's revenues.

The Partnership's future operations are expected to be conducted with available funds and revenues generated from natural gas, NGLs and crude oil production activities and commodity derivatives. Natural gas, NGLs and crude oil production from the Partnership's existing properties are generally expected to continue a gradual decline in the rate of production over the remaining life of the wells. Therefore, the Partnership anticipates a lower annual level of natural gas, NGLs and crude oil production and, in the absence of significant price increases or additional reserve development, lower revenues. The Partnership also expects cash flows from operations to decline if commodity prices remain at current levels or decrease in the future. Under these circumstances decreased production would have a material negative impact on the Partnership's operations and may result in reduced cash distributions to the Managing General Partner and Investor Partners through the remainder of 2011 and beyond, and may substantially reduce or restrict the Partnership's ability to participate in the refracturing activities which are more fully described in Item 2, Management's Discussion and Analysis of Financial Condition and Results of Operations, Recent Developments−Well Refracturing Plan.

Although the Agreement permits the Partnership to borrow funds on its behalf for Partnership activities, the Managing General Partner does not anticipate electing to fund through bank borrowings, any portion of the Partnership's refracturing activities. These refracturings and recompletions are scheduled to begin in 2012. Partnership borrowings, should any occur, will be non-recourse to the Investor Partners; accordingly, the Partnership, not the Investor Partners, will be responsible for repaying the loan.

-22-

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Working Capital

The Partnership had working capital of $3.5 million at September 30, 2011 compared to working capital of $1.9 million at December 31, 2010, an increase of $1.6 million. This increase was primarily due to the following changes:


•	Cash and cash equivalents increased by $1.3 million between September 30, 2011 and December 31, 2010.


•	Accounts receivable decreased by $0.8 million between September 30, 2011 and December 31, 2010.


•	Realized and unrealized derivative gains receivable increased by $0.6 million between September 30, 2011 and December 31, 2010.


•	Due to the Managing General Partner, excluding natural gas, NGLs and crude oil sales received from third parties and realized derivative gains, decreased by $0.4 million between September 30, 2011 and December 31, 2010.


•	Accounts payable and accrued expenses decreased by $0.1 million between September 30, 2011 and December 31, 2010.

Working capital is expected to increase during periods of Well Refracturing Plan funding and decrease during periods when payments are made for refracturing.

Cash Flows

Cash Flows From Operating Activities

The Partnership's cash flows provided by operating activities are primarily impacted by commodity prices, production volumes, realized gains and losses from its derivative positions, operating costs and general and administrative expenses. See Results of Operations above for an additional discussion of the key drivers of cash flows provided by operating activities.

Natural gas, NGLs and crude oil prices exhibit a high degree of volatility. These price variations have a material impact on the Partnership's financial results. Natural gas and NGLs prices vary by region and locality, depending upon the distance to markets, the availability of pipeline capacity and the supply and demand relationships in that region or locality. This can be especially true in the Rocky Mountain Region. The combination of increased drilling activity and the lack of local markets has resulted in local market oversupply situations from time to time. Like most producers in the region, the Partnership relies on major interstate pipeline companies to construct these pipelines to increase capacity, rendering the timing and availability of these facilities beyond the Partnership's control. Crude oil pricing is predominantly driven by the physical market, supply and demand, the financial markets and global unrest.

The price at which PDC markets the natural gas produced in the Rocky Mountain Region by the Partnership is based on a market basket of prices, which generally includes natural gas sold at, near or below CIG prices in addition to other nearby region prices. The CIG Index and other indices for production delivered to other Rocky Mountain pipelines have historically been less than the price received for natural gas produced in the eastern regions, which is primarily New York Mercantile Exchange, or NYMEX, based. This negative differential has narrowed over the last few years and is lower than historical variances. The negative differential of CIG relative to NYMEX averaged $0.28 and $0.30 for the three and nine months ended September 30, 2011, respectively, compared to an average of $0.51 and $0.88 for the three and nine months ended September 30, 2010, respectively.

The price the Partnership receives on its natural gas sales is impacted by the Managing General Partner's transportation, gathering and processing agreements. The Partnership currently uses the "net-back" method of accounting for these arrangements related to the Partnership's natural gas sales. The Partnership sells natural gas at the wellhead and collects a price and recognizes revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by the purchaser and reflected in the wellhead price. The net-back method results in the recognition of a sales price that is below the indices for which the production is based.

-23-

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Net cash provided by operating activities was $3.5 million for the nine months ended September 30, 2011, compared to $8.5 million for the comparable period in 2010. The decrease of $5.0 million in cash provided by operating activities was due primarily to the following:


•	A decrease in natural gas, NGLs and crude oil sales receipts of $2.7 million, or 31%,


•	A decrease in commodity price risk management realized gains receipts of $1.8 million, or 80%, and


•	An increase in production costs and direct costs - general and administrative payments of $0.4 million.

Cash Flows From Investing Activities

The Partnership, from time-to-time, invests in equipment which supports treatment, delivery and measurement of natural gas, NGLs and crude oil or environmental protection. These amounts totaled $0.1 million and $1.2 million for the nine months ended September 30, 2011 and 2010, respectively.

In February 2011, the Managing General Partner executed a purchase and sale agreement for the Partnership's North Dakota assets and subsequently closed with the same unrelated third party. Proceeds from the sale were $5.7 million.

Cash Flows From Financing Activities

The Partnership initiated monthly cash distributions to investors in May 2007 and has distributed $78.7 million through September 30, 2011. The table below presents cash distributions to the Partnership's investors. Distributions to the Managing General Partner represent amounts distributed to PDC for the Managing General Partner's 37% general partner interest in the Partnership. Investor Partner distributions include amounts distributed to Investor Partners for their 63% ownership share in the Partnership and include amounts distributed to PDC for limited partnership units repurchased.



Distributions

Three months ended September 30,	Managing General Partner		Investor Partners		Total
2011	$	331,042	$	563,666	$	894,708
2010	578,515		985,039		1,563,554

Nine months ended September 30,	Managing General Partner		Investor Partners		Total
2011	$	2,902,025	$	4,941,284	$	7,843,309
2010	2,559,730		4,358,458		6,918,188

The increase in total distributions for 2011 as compared to 2010 is primarily due to the Partnership distributing $4.7 million of the proceeds from the sale of the North Dakota assets to the Investor Partners and Managing General Partner offset in part by the significant decrease in cash flows from operating activities during 2011and from funds held by the Managing General Partner for the Well Refracturing Plan. The Partnership began funding for the Well Refracturing Plan during October 2010. During the quarter ended September 30, 2011, on a pro-rata basis based on percentage of ownership in the Partnership, the Partnership withheld $18,500 and $31,500 from the Managing General Partner and Investor Partners' share of cash available for distributions, respectively. During the nine months ended September 30, 2011, on a pro-rata basis based on percentage of ownership in the Partnership, the Partnership withheld $555,000 and $945,000 from the Managing General Partner and Investor Partners' share of cash available for distributions, respectively.

Off-Balance Sheet Arrangements

As of September 30, 2011, the Partnership had no existing off-balance sheet arrangements, as defined under SEC rules, which have or are reasonably likely to have a material current or future effect on the Partnership's financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

Commitments and Contingencies

See Note 6, Commitments and Contingencies, to the accompanying unaudited condensed financial statements, included in this report.

-24-

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Recent Accounting Standards

See Note 2, Recent Accounting Standards, to the accompanying unaudited condensed financial statements, included in this report.

Critical Accounting Policies and Estimates

The preparation of the accompanying unaudited condensed financial statements in conformity with U.S. GAAP requires management to use judgment in making estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities and the reported amounts of revenue and expenses.

There have been no significant changes to the Partnership's critical accounting policies and estimates or in the underlying accounting assumptions and estimates used in these critical accounting policies from those disclosed in the financial statements and accompanying notes contained in the Partnership's 2010 Form 10-K.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Not applicable.

Item 4. Controls and Procedures

The Partnership has no direct management or officers. The management, officers and other employees that provide services on behalf of the Partnership are employed by the Managing General Partner.

(a) Evaluation of Disclosure Controls and Procedures

As of September 30, 2011, PDC, as Managing General Partner on behalf of the Partnership, carried out an evaluation, under the supervision and with the participation of the Managing General Partner's management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the Partnership's disclosure controls and procedures pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e). This evaluation considered the various processes carried out under the direction of the Managing General Partner's disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports that the Partnership files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC's rules and forms, and that such information is accumulated and communicated to the Partnership's management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely discussion regarding required disclosure.

Based on the results of this evaluation, the Managing General Partner's Chief Executive Officer and the Chief Financial Officer concluded that the Partnership's disclosure controls and procedures were effective as of September 30, 2011.

(b) Changes in Internal Control over Financial Reporting

During the three months ended September 30, 2011, PDC, the Managing General Partner, made no changes in the Partnership's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) that have materially affected or are reasonably likely to materially affect the Partnership's internal control over financial reporting.

-25-

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

Item 1A. Risk Factors

Not applicable.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Unit Repurchase Program: Beginning May 2010, the third anniversary of the date of the first Partnership cash distributions, Investor Partners of the Partnership may request that the Managing General Partner repurchase their respective individual Investor Partner units, up to an aggregate total limit during any calendar year for all requesting Investor Partner unit repurchases of 10% of the initial subscription units.

There were no limited partner unit repurchases by the Managing General Partner during the three months ended September 30, 2011.

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. [Removed and Reserved]

Item 5. Other Information

Not applicable.

-26-

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Item 6. Exhibits

The exhibits presented below are in addition to those presented in the Partnership's Form 10-K and subsequent quarterly filings on Form 10-Q.

Incorporated by Reference

Exhibit

Number

Exhibit Description

Form

SEC File

Number

Exhibit

Filing Date

Filed

Herewith

31.1

Certification by Chief Executive Officer of Petroleum Development Corporation (dba PDC Energy), the Managing General Partner of the Partnership, pursuant to Rule 13a-14(a)/15d-14(c) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2

Certification by Chief Financial Officer of Petroleum Development Corporation (dba PDC Energy), the Managing General Partner of the Partnership, pursuant to Rule 13a-14(a)/15d-14(c) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1**

Certifications by Chief Executive Officer and Chief Financial Officer of Petroleum Development Corporation (dba PDC Energy), the Managing General Partner of the Partnership, pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS**

XBRL Instance Document

101.SCH**

XBRL Taxonomy Extension Schema Document

101.CAL**

XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF**

XBRL Taxonomy Extension Definition Linkbase Document

101.LAB**

XBRL Taxonomy Extension Label Linkbase Document

101.PRE**

XBRL Taxonomy Extension Presentation Linkbase Document

**Furnished herewith.

-27-

Index

ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Rockies Region 2006 Limited Partnership

By its Managing General Partner

Petroleum Development Corporation (dba PDC Energy)



	By: /s/ James M. Trimble
	James M. Trimble Chief Executive Officer of Petroleum Development Corporation (dba PDC Energy)
	November 14, 2011

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated:



Signature	Title	Date

/s/ James M. Trimble	Chief Executive Officer	November 14, 2011
James M. Trimble	Petroleum Development Corporation (dba PDC Energy) Managing General Partner of the Registrant
	(Principal executive officer)

/s/ Gysle R. Shellum	Chief Financial Officer	November 14, 2011
Gysle R. Shellum	Petroleum Development Corporation (dba PDC Energy) Managing General Partner of the Registrant
	(Principal financial officer)

/s/ R. Scott Meyers	Chief Accounting Officer	November 14, 2011
R. Scott Meyers	Petroleum Development Corporation (dba PDC Energy) Managing General Partner of the Registrant
	(Principal accounting officer)

-28-

Attached files

Rockies Region 2006 Limited Partnership Reports

Also read