Rockies Region 2006 Limited Partnership 10-Q 2010 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2010

or

o 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 files) and (2) has been subject to such filing requirements for the past 90 days.

Yes þ No o

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 o No o

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 definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act:

Large accelerated filer o	Accelerated filer o
Non-accelerated filer o	Smaller reporting company þ

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

As of September 30, 2010 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

		Page
	PART I – FINANCIAL INFORMATION
	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	12
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	23
Item 4.	Controls and Procedures	23
	PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	24
Item 1A.	Risk Factors	24
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	24
Item 3.	Defaults Upon Senior Securities	24
Item 4.	[Removed and Reserved]	24
Item 5.	Other Information	24
Item 6.	Exhibits	25
	SIGNATURES	28

NOTE REGARDING FORWARD-LOOKING STATEMENTS

This periodic report contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (“Exchange Act”) regarding Rockies Region 2006 Limited Partnership’s (the “Partnership” or the “Registrant”) business, financial condition, results of operations and prospects.

All statements other than statements of historical facts included in and incorporated by reference into this report are forward-looking statements.  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, which include statements of estimated natural gas and oil production and reserves, drilling plans, future cash flows, anticipated liquidity, anticipated capital expenditures and the Managing General Partner Petroleum Development Corporation’s (“PDC”) strategies, plans and objectives. However, these words are not the exclusive means of identifying forward-looking statements herein.  PDC now conducts business under the name “PDC Energy.”

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 risks and uncertainties incidental to the development, production and marketing of natural gas and 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, worldwide demand, and commodity prices for natural gas and oil;

● changes in estimates of proved reserves;

● declines in the values of the Partnership’s natural gas and oil properties resulting from impairments;

● the timing and extent of the Partnership’s success in further developing and producing the Partnership’s natural gas and oil reserves;

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

● risks incident to the refracturing and operation of natural gas and oil wells;

● future production and refracturing costs;

● the availability of Partnership future cash flows for investor distributions or funding of Well Refracturing Plan activities;

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

● the effect of existing and future laws, governmental regulations and the political and economic climate of the United States of America, or U.S.;

● changes in environmental laws and the regulations and enforcement related to those laws;

● the identification of and severity of environmental events and governmental responses to the events;

● the effect of natural gas and oil derivatives activities;

● the availability of funding for the consideration payable by PDC and its wholly-owned subsidiary to consummate the prospective mergers under the Acquisition Plan;

● the timing and closing, if consummated, of the proposed merger of the 2004 partnerships with and into a wholly-owned subsidiary of PDC;

● conditions in the capital markets; and

● losses possible from pending or future litigation.

Further, the Partnership urges the reader to carefully review and consider the cautionary statements made in this report, the Partnership’s annual reports on Form 10-K and Form 10-K/A for the year ended December 31, 2009 filed with the Securities and Exchange Commission, or SEC, on March 31, 2010 and August 27, 2010 (“2009 Form 10-K” or “2009 Form 10-K/A”, respectively) and the Partnership’s other filings with the SEC and public disclosures.  The Partnership cautions you not to place undue reliance on forward-looking statements, which speak only as of the date made.  Other than as required under the securities laws, the Partne rship 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.

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PART I – FINANCIAL INFORMATION

Item 1. Financial Statements (unaudited)

Rockies Region 2006 Limited Partnership

Condensed Balance Sheets

(unaudited)

	September 30,			December 31,
	2010			2009*
Assets
Current assets:
Cash and cash equivalents	$	352,801		$	5,278
Accounts receivable		732,613			1,022,281
Oil inventory		43,740			44,266
Due from Managing General Partner-derivatives		2,158,446			1,414,982
Due from Managing General Partner-other, net		632,055			413,982
Total current assets		3,919,655			2,900,789
Oil and gas properties, successful efforts method, at cost		97,976,944			97,856,261
Less: Accumulated depreciation, depletion and amortization		(40,344,537	)		(35,009,030	)
Oil and gas properties, net		57,632,407			62,847,231
Due from Managing General Partner-derivatives		3,360,812			1,084,358
Total noncurrent assets		60,993,219			63,931,589
Total Assets	$	64,912,874		$	66,832,378
Liabilities and Partners’ Equity
Current liabilities:
Accounts payable and accrued expenses	$	255,558		$	129,730
Due to Managing General Partner-derivatives		1,269,651			1,180,416
Total current liabilities		1,525,209			1,310,146
Due to Managing General Partner-derivatives		2,477,964			3,221,492
Asset retirement obligations		1,083,412			1,039,044
Total liabilities		5,086,585			5,570,682
Commitments and contingent liabilities
Partners’ equity:
Managing General Partner		17,199,713			17,730,814
Limited Partners - 4,497.03 units issued and outstanding		42,626,576			43,530,882
Total Partners’ equity		59,826,289			61,261,696
Total Liabilities and Partners’ Equity	$	64,912,874		$	66,832,378

*Derived from audited 2009 balance sheet

See accompanying notes to unaudited condensed financial statements.

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Rockies Region 2006 Limited Partnership

Condensed Statements of Operations

(unaudited)

	Three months ended September 30,					Nine months ended September 30,
	2010		2009			2010		2009
Revenues:
Natural gas and oil sales	$	2,296,332	$	2,703,900		$	8,224,913	$	7,718,377
Commodity price risk management gain (loss), net		1,776,663		(1,311,921	)		5,223,103		(3,236,519	)
Total revenues		4,072,995		1,391,979			13,448,016		4,481,858
Operating costs and expenses:
Natural gas and oil production costs		865,030		902,587			2,466,288		2,740,184
Direct costs - general and administrative		35,402		82,344			119,072		451,902
Depreciation, depletion and amortization		1,635,865		2,220,461			5,335,507		7,115,045
Exploratory dry hole costs		—		37,162			—		37,243
Accretion of asset retirement obligations		14,998		10,139			44,368		30,417
Total operating costs and expenses		2,551,295		3,252,693			7,965,235		10,374,791
Income (loss) from operations		1,521,700		(1,860,714	)		5,482,781		(5,892,933	)
Interest expense		—		(5,892	)		—		(5,892	)
Interest income		—		—			—		7,418
Net income (loss)	$	1,521,700	$	(1,866,606	)	$	5,482,781	$	(5,891,407	)
Net income (loss) allocated to partners	$	1,521,700	$	(1,866,606	)	$	5,482,781	$	(5,891,407	)
Less: Managing General Partner interest in net income (loss)		563,029		(690,645	)		2,028,629		(2,179,821	)
Net income (loss) allocated to Investor Partners	$	958,671	$	(1,175,961	)	$	3,454,152	$	(3,711,586	)
Net income (loss) per Investor Partner unit	$	213	$	(261	)	$	768	$	(825	)
						��
Investor Partner units outstanding		4,497.03		4,497.03			4,497.03		4,497.03

See accompanying notes to unaudited condensed financial statements.

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Rockies Region 2006 Limited Partnership

Condensed Statements of Cash Flows

(unaudited)

	Nine months ended September 30,
	2010			2009
Cash flows from operating activities:
Net income (loss)	$	5,482,781		$	(5,891,407	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		5,335,507			7,115,045
Accretion of asset retirement obligations		44,368			30,417
Unrealized (gain) loss on derivative transactions		(3,674,211	)		8,593,021
Exploratory dry hole costs		—			37,243
Changes in operating assets and liabilities:
Decrease in accounts receivable		289,668			433,655
Decrease in oil inventory		526			9,688
Increase (decrease) in accounts payable and accrued expenses		125,828			(102,030	)
Decrease in due from Managing General Partner - other, net		850,584			2,372,921
Increase in due to Managing General Partner - other, net		—			591,353
Net cash provided by operating activities		8,455,051			13,189,906
Cash flows from investing activities:
Capital expenditures for oil and gas properties		(1,189,340	)		(174,308	)
Proceeds from sale of equipment		—			40,048
Proceeds from Colorado sales tax refund related to capital purchases		—			50,047
Net cash used in investing activities		(1,189,340	)		(84,213	)
Cash flows from financing activities:
Distributions to Partners		(6,918,188	)		(13,303,848	)
Net cash used in financing activities		(6,918,188	)		(13,303,848	)
Net increase (decrease) in cash and cash equivalents		347,523			(198,155	)
Cash and cash equivalents, beginning of period		5,278			203,462
Cash and cash equivalents, end of period	$	352,801		$	5,307
Supplemental disclosure of non-cash activity:
Change in Due to/from Managing General Partner-other, net related to purchases of properties and equipment	$	(1,068,657	)	$	—

See accompanying notes to unaudited condensed financial statements.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 2010

(unaudited)

Note 1−General and Basis of Presentation

The Rockies Region 2006 Limited Partnership (the "Partnership") was organized as a limited partnership on July 20, 2006 in accordance with the laws of the State of West Virginia for the purpose of engaging in the exploration and development of oil and natural gas properties.  Upon completion of the private placement of Partnership units on September 7, 2006, the Partnership was funded and commenced its business operations.  The Partnership owns natural gas and oil wells located in Colorado and from the wells, the Partnership produces and sells natural gas and oil.

Purchasers of partnership units subscribed to and fully paid for 47.25 units of limited partner interests and 4,449.78 units of additional general partner interests at $20,000 per unit.  In accordance with the terms of the Limited Partnership Agreement (the “Agreement”), Petroleum Development Corporation, a Nevada Corporation that now conducts business under the name “PDC Energy”, is the Managing General Partner of the Partnership (hereafter, the “Managing General Partner” or “PDC”) and has a 37% Managing General Partner ownership in the Partnership.  Upon completion of the drilling phase of the Partnership's wells, all additional general partners units were converted into units of limited partner interests and thereafter became limited partners of the Partnership.
60; Throughout the term of the Partnership, revenues, costs, and cash distributions are allocated 63% to the limited and additional general partners (collectively, the “Investor Partners”), which are shared pro rata based upon the portion of units owned in the Partnership, and 37% to the Managing General Partner.

As of September 30, 2010, there were 2,025 Investor Partners.  As of September 30, 2010, the Managing General Partner has repurchased 13.0 units of the total 4,497.03 outstanding units of Partnership interests from Investor Partners at an average price of $8,586 per unit and, as a result, participates in the sharing of revenues, costs and cash distributions as both an investor partner and as the Managing General Partner.

The Managing General Partner, under the terms of the Drilling and Operating Agreement (the “D&O Agreement”), has full authority to conduct the Partnership’s business and actively manage the Partnership.  The Partnership expects continuing operations of its natural gas and oil properties until such time that the Partnership’s wells are depleted or become uneconomical to produce, at which time that well 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 10 of Regulation S-X of the Securities and Exchange Commission, or SEC.  Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in 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 fina ncial statements and notes thereto included in the Partnership’s 2009 Form 10-K.  The Partnership’s accounting policies are described in the Notes to Financial Statements in the Partnership’s 2009 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, 2010, and the cash flows for the nine months ended September 30, 2010, are not necessarily indicative of the results to be expected for the full year or any other future period.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 2010

(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 clarifying existing disclosure requirements related to fair value measurements.  The update also added a new requirement to disclose fair value transfers in and out of Levels 1 and 2 and describe the reasons for the transfers.  The adoption of these changes as of January 1, 2010, did not have a material impact on the Partnership’s accompanying unaudited condensed financial statements.

Recently Issued Accounting Standards

Fair Value Measurements and Disclosures

In January 2010, the 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.  This change will be effective for the Partnership’s financial statements issued for annual reporting periods beginning after December 15, 2010.  The Partnership does not expect adoption of these changes to have a material effect on the Partnership’s financial statements and related disclosures.

Internal Control over Financial Reporting in Exchange Act Periodic Reports

By Final Rule effective September 21, 2010, the SEC amended its rules and forms to conform them to Section 404(c) of the Sarbanes-Oxley Act of 2002, or SOX, as added by the Dodd-Frank Wall Street Reform and Consumer Protection Act.  The new SEC rules exempt the Partnership, as a smaller reporting company filer, from the SOX requirement that registrants which are accelerated or large accelerated filers, obtain and include in their annual report filed with the SEC, their independent registered public accounting firm’s attestation report on the effectiveness of the registrant’s internal controls over financial reporting.

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 unexpired derivative instruments is recorded on the balance sheet under the captions “Due from Managing General Partner–derivatives,” in the case of net unrealized gains or “Due to Managing General Partner–derivatives,” in the case of net unrealized losses.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 2010

(unaudited)

The following table presents transactions with the Managing General Partner reflected in the balance sheet line item – Due from (to) Managing General Partner-other, net which remain undistributed or unsettled with the Partnership’s investors as of the dates indicated.

	September 30, 2010			December 31, 2009
Natural gas and oil sales revenues collected from the Partnership’s third-party customers	$	787,238		$	1,073,920
Commodity Price Risk Management, Realized Gains		212,049			963,873
Other (1)(2)		(367,232	)		(1,623,811	)
Total Due from Managing General Partner-other, net	$	632,055		$	413,982

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

(2) At December 31, 2009, this amount includes the Partnership’s liability recorded in the account “Due to Managing General Partner - other” for additional drilling costs of $1,068,657 incurred in 2008, which were in excess of drilling advances paid to the Managing General Partner.  During the nine months ended September 30, 2010, distributable cash flows of $1,068,657 were retained for the full payment of this obligation.

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, 2010 and 2009.  “Well operations and maintenance” and “Gathering, compression and processing fees” are included in “Natural gas and oil production costs” on the statements of operations.

	Three months ended September 30,				Nine months ended September 30,
	2010		2009		2010		2009
Well operations and maintenance	$	646,183	$	684,765	$	1,794,455	$	2,147,570
Gathering, compression and processing fees		70,440		54,376		277,794		157,125
Direct costs - general and administrative		35,402		82,344		119,072		451,902
Cash distributions*		580,562		1,607,263		2,567,778		4,930,587

*Cash distributions include $2,047 and $8,048 during the three and nine months ended September 30, 2010, respectively, and $2,510 and $8,166 during the three and nine months ended September 30, 2009, respectively, related to equity cash distributions on Investor Partner units repurchased by PDC.

Note 4−Fair Value Measurements

Derivative Financial Instruments.  The Partnership measures fair value based upon quoted market prices, where available.  The valuation determination includes: (1) identification of the inputs to the fair value methodology through the review of counterparty statements and other supporting documentation, (2) determination of the validity of the source of the inputs, (3) 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.  The methods described above may produce a fair value calculation that may not be indicative of fu ture fair values.  The valuation determination also gives consideration to nonperformance risk on Partnership liabilities in addition to nonperformance risk on PDC’s own business interests and liabilities, as well as the credit standing of derivative instrument counterparties.  The Managing General Partner primarily uses financial institutions, which are also major lenders in PDC’s credit facility agreement, as counterparties to the Partnership’s derivative contracts.  The Managing General Partner has evaluated the credit risk of the counterparties holding the Partnership’s derivative assets using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position.  Based on the Managing General Partner’s evaluation, as of September 30, 2010, the impact of non-performance risk on the fair value of the Partnership’s derivative assets and liabi lities was not significant.  Validation of the Partnership’s contracts’ fair values are performed internally and while the Managing General Partner uses common industry practices to develop valuation techniques, changes in the Managing General Partner’s pricing methodologies or the underlying assumptions could result in significantly different fair values.  While the Managing General Partner believes these valuation methods are appropriate and consistent with those used by other market participants, the use of different methodologies, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 2010

(unaudited)

The following table presents, by hierarchy level, the Partnership’s derivative financial instruments, including both current and non-current portions measured at fair value.

	Quoted Prices in Active Markets			Significant Unobservable Inputs
	(Level 1)			(Level 3)			Total
As of December 31, 2009
Assets:
Commodity based derivatives	$	1,094,091		$	1,405,249		$	2,499,340
Total assets		1,094,091			1,405,249			2,499,340
Liabilities:
Commodity based derivatives		(90,257	)		(296,710	)		(386,967	)
Basis protection derivative contracts		—			(4,014,941	)		(4,014,941	)
Total liabilities		(90,257	)		(4,311,651	)		(4,401,908	)
Net asset (liability)	$	1,003,834		$	(2,906,402	)	$	(1,902,568	)
As of September 30, 2010
Assets:
Commodity based derivatives	$	5,014,235		$	505,023		$	5,519,258
Total assets		5,014,235			505,023			5,519,258
Liabilities:
Commodity based derivatives		—			(261,640	)		(261,640	)
Basis protection derivative contracts		—			(3,485,975	)		(3,485,975	)
Total liabilities		—			(3,747,615	)		(3,747,615	)
Net asset (liability)	$	5,014,235		$	(3,242,592	)	$	1,771,643

The following table presents the changes of the Partnership’s Level 3 derivative financial instruments measured on a recurring basis:

	Nine months ended  September 30, 2010
Fair value, net liability, as of December 31, 2009	$	(2,906,402	)
Changes in fair value included in statement of operations line item:
Commodity price risk management, net		449,351
Settlements		(785,541	)
Fair value, net liability, as of September 30, 2010	$	(3,242,592	)
Change in unrealized gains (losses) relating to assets (liabilities) still held as of September 30, 2010 included in statement of operations line item:
Commodity price risk management, net	$	105,607

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

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 2010

(unaudited)

Non-Derivative 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.

Note 5−Derivative Financial Instruments

As of September 30, 2010, the Partnership had derivative instruments, comprised of commodity collars, commodity fixed-price swaps and basis protection swaps, in place for a portion of its anticipated production through 2013 for a total of 2,844,732 MMbtu of natural gas and 30,488 Bbls of oil.  Partnership policy prohibits the use of natural gas and oil derivative instruments for speculative purposes.

The following table summarizes the line item and fair value amounts of the Partnership’s derivative instruments in the accompanying balance sheets.

			Fair Value
Derivative instruments not designated as hedge (1):		Balance Sheet Line Item	September 30, 2010		December 31, 2009
Derivative Assets:	Current
	Commodity contracts	Due from Managing General
		Partner-derivatives	$	2,158,446	$	1,414,982
	Non Current
	Commodity contracts	Due from Managing General
		Partner-derivatives		3,360,812		1,084,358
Total Derivative Assets			$	5,519,258	$	2,499,340
Derivative Liabilities:	Current
	Commodity contracts	Due to Managing General
		Partner-derivatives	$	190,743	$	92,588
	Basis protection contracts	Due to Managing General
		Partner-derivatives		1,078,908		1,087,828
	Non Current
	Commodity contracts	Due to Managing General
		Partner-derivatives		70,897		294,379
	Basis protection contracts	Due to Managing General
		Partner-derivatives		2,407,067		2,927,113
Total Derivative Liabilities			$	3,747,615	$	4,401,908

(1) As of September 30, 2010 and December 31, 2009, none of the Partnership’s derivative instruments were designated as hedges.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 2010

(unaudited)

The following table summarizes the impact of the Partnership’s derivative instruments on the Partnership’s accompanying statements of operations for the three and nine months ended September 30, 2010 and 2009.

	Three months ended September 30,
	2010							2009
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 Losses For the Current Period			Total
Commodity price risk management, net
Realized gains (losses)	$	112,014		$	123,862	$	235,876	$	1,328,325		$	(2,953	)	$	1,325,372
Unrealized (losses) gains		(112,014	)		1,652,801		1,540,787		(1,328,325	)		(1,308,968	)		(2,637,293	)
Total commodity price risk management gain (loss), net	$	—		$	1,776,663	$	1,776,663	$	—		$	(1,311,921	)	$	(1,311,921	)

	Nine months ended September 30,
	2010							2009
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 (Losses) For the Current Period			Total
Commodity price risk management, net
Realized gains	$	383,673		$	1,165,219	$	1,548,892	$	4,352,668		$	1,003,834		$	5,356,502
Unrealized (losses) gains		(383,673	)		4,057,884		3,674,211		(4,352,668	)		(4,240,353	)		(8,593,021	)
Total commodity price risk management gain (loss), net	$	—		$	5,223,103	$	5,223,103	$	—		$	(3,236,519	)	$	(3,236,519	)

Concentration of Credit Risk. A significant component of the Partnership’s future liquidity is concentrated in derivative instruments that enables the Partnership to manage a portion of its exposure to price volatility from producing natural gas and oil.  These arrangements expose the Partnership to the 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 the derivative contracts.  To date, the Partnership has experienced no counterparty defaults.

Note 6−Commitments and Contingencies

Environmental

Due to the nature of the natural gas and oil business, the Partnership is exposed to environmental risks.  The Managing General Partner has various policies and procedures 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 assessments and/or clean-ups are probable and the costs can be reasonably estimated.  During the second quarter of 2010, the Managing General Partner identified existing ground contamination at three Partnership well sites containing nine Partnership wells.  The accrual of appr oximately $200,000 was the estimated cost attributable to the Partnership, based principally on estimated third party costs, to remediate the ground contamination.  The Partnership recorded the accrued environmental remediation liability in Balance Sheet line item captioned “Accounts payable and accrued expenses.” This accrual represented costs estimated to be incurred in addition to normal recurring environmental-related expenditures which have been incurred and recorded at June 30, 2010.  At September 30, 2010, this accrued environmental liability is $153,000, which represents the remaining estimated costs to complete environmental remediation activities at these Partnership well sites, less costs incurred through September 30, 2010, if any.  The Managing General Partner is not aware of any environmental claims existing as of September 30, 2010, which have not been provided for or would otherwise have a material impact on the Partnership’s financial statement s.  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.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

September 30, 2010

(unaudited)

In December 2008, the Managing General Partner received a Notice of Violation/Cease and Desist Order (the “Notice”) from the Colorado Department of Public Health and Environment (the “CDPHE”), related to the stormwater permit for the Garden Gulch Road.  The Managing General Partner manages this private road for Garden Gulch LLC.  The Managing General Partner is one of eight users of this road, all of which are natural gas and oil companies operating in the Piceance region of Colorado.  Operating expenses, including this fine, if any, are allocated among the users of the road based upon their respective usage.  The Partnership has 23 wells in this region.  The Notice alleged a deficient and/or incomplete stormwater management plan, failure to implement best manag ement practices and failure to conduct required permit inspections.  The Notice requires corrective action and states that the recipient shall cease and desist such alleged violations.  The Notice states that a violation could result in civil penalties up to $10,000 per day.  The Managing General Partner’s responses were submitted on February 6, 2009, and April 8, 2009.  Commencing in December 2009, the Managing General Partner entered into negotiations with the CDPHE regarding this notice and continues to work to bring this matter to closure.  Given the inherent uncertainty in administrative actions of this nature, the Managing General Partner is unable to predict with certainty the ultimate outcome of this administrative action; however, the Managing General Partner does not believe that the ultimate outcome will have a material adverse effect on the Partnership’s financial position or results of operations.

Note 7−Subsequent Events

On October 20, 2010, the Managing General Partner notified Investor Partners by letter, that the Partnership commenced the withholding of funds, on a pro-rata basis allocated to the Managing General Partner and Investor Partners based on their proportional ownership interest, which will be utilized to further develop the Partnership’s Denver-Julesburg (“DJ”) Basin Wattenberg Field wells under the previously announced Well Refracturing Plan.  The plan provides for the refracturing of the Partnership’s Wattenberg Field wells in the currently producing Codell formation and these activities are expected to begin mid-to-late 2011.  Funds withheld from the Partnership’s investors in the October 2010 distribution amounted to $20,000 and have been deposited in the Partnership’s bank acco unt.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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 and oil.  The Partnership began natural gas and oil operations in September 2006 and operates 91 gross (89.7 net) producing wells located in the Rocky Mountain Region in the states of Colorado and North Dakota.  The Partnership drilled six additional wells determined to be dry holes: one developmental dry hole and three exploratory dry holes in Colorado and two exploratory dry holes in North Dakota. The Managing General Partner markets the Partnership’s natural gas production to commercial end users, interstate or intrastate pipelines or local utilities, primarily under market sensitive contracts in which the price of natural gas sold varies as a result of market forces.  PDC does not charge an add itional fee for the marketing of the natural gas and 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.

PDC Sponsored Drilling Program Acquisition Plan

PDC, the managing general partner of various public limited partnerships, has disclosed its intention to pursue the acquisitions, within the next three years beginning in the fall of 2010, of the remaining third-party Investor Partner interests in the limited partnerships which PDC has sponsored (the “Acquisition Plan”), including this Partnership.  (For additional information regarding PDC’s intention to pursue acquisitions of PDC sponsored partnerships, refer to the disclosure included in Items 2.02 and/or 7.01 of PDC’s Forms 8-K dated March 4, 2010, June 9, 2010 and July 15, 2010, which 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 mer ger offer will be subject to the terms and conditions of the related merger agreement and such agreement does or will likely contemplate the partnership being merged with and into a wholly owned subsidiary of PDC.  The transaction will also be subject to, among other things, PDC having sufficient available capital and the approval by a majority of the limited partnerships units held by the Investor Partners, excluding limited partnership units owned by PDC or its affiliates, of each respective limited partnership. Consummation of any proposed merger under the Acquisition Plan will likely result in the termination of the existence of that partnership and the right for third-party Investor Partners to receive a cash payment for their limited partnership units in that partnership.

In June 2010, PDC and a wholly owned subsidiary of PDC entered into a merger agreement with PDC 2004-A Limited Partnership, PDC 2004-B Limited Partnership, PDC 2004-C Limited Partnership and PDC 2004-D Limited Partnership (collectively, the “2004 partnerships”).  PDC serves as the managing general partner of each of the 2004 partnerships.  Pursuant to each merger agreement, if the merger is approved by the holders of a majority of the limited partnership units held by Investor Partners of that partnership not owned by PDC or its affiliates, as well as the satisfaction of other customary closing conditions, then the partnership will merge with and into a wholly owned subsidiary of PDC.  If all four 2004 partnerships are acquired, PDC will pay up to an aggregate of approximately $36.4 million for t he limited partnership units of these partnerships. Definitive proxy statements for each of the 2004 partnerships requesting approval from the applicable third-party Investor Partners for, among other things, the merger agreements were mailed to the third-party Investor Partners of the 2004 partnerships in early October 2010. The special meetings whereby third-party Investor Partners of the 2004 partnerships will have an opportunity to vote and approve the applicable merger agreement are currently scheduled for December 8, 2010 for each of the 2004 partnerships. If the required approvals are received from the third-party Investor Partners at the special meetings, each of the mergers for the 2004 partnerships is expected to close shortly thereafter and no later than December 31, 2010. The feasibility and timing of any future 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 lim ited 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 to gaining all necessary regulatory approvals required for a merger and repurchase offer.  There is no assurance that any merger and acquisition will occur as a result of the proposed repurchase offers to PDC’s 2004 partnerships, or any potential proposed repurchase offer to any other of PDC’s various public limited partnerships, including this Partnership, should they occur.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Well Refracturing Plan

The Managing General Partner has developed the Well Refracturing Plan for the Partnership’s Wattenberg Field wells that were initially completed in the Codell formation during the Partnership’s initial development. Under the plan, the Partnership will initiate Codell formation refracturing activities during 2011.  These refracturing, or “refracing”, activities will consist of a second hydraulic fracturing treatment to the currently producing Codell formation.

Funding of the initial well refracturing activity began with the withholding, on a pro-rata basis, of $20,000 from the Partnership’s October 2010 monthly distributable cash flows which was allocated to the Managing General Partner and Investor Partners based on their proportional ownership interest.  This withholding was deposited into the Partnership’s bank account.

After the initial refrac funding is completed in 2011, the Partnership will re-evaluate the Well Refracturing Plan funding requirements and will continue to withhold cash at varying levels on a pro-rata basis, from the Managing General Partner’s and Investor Partner’s distributable cash flows from current production operations.  The most recent cost projection for Codell formation well refracturing ranges between $150,000 and $200,000 per refrac.  Total withholding from the Partnership’s distributable cash flows for the Partnership’s 59 well refracturing opportunities is estimated to be between $8.9 million and $11.8 million.  The number of refracturings and the timing of refracturing will be based on the availability of cash withheld from Partnership distributions.  The necessary funds to be retained by the Partnership for the payment of Well Refracturing Plan activities may materially reduce, up to 100%, of the Managing General Partner’s and Investor Partners’ distributable cash flows for a period of time not to exceed five years.

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 distributable cash flows 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 interes t.  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.

Partnership Operating Results Overview

Natural gas and oil sales increased 7% or $0.5 million for the first nine months of 2010 compared to the first nine months of 2009, even though production volumes decreased 29% period-to-period.  This increase was driven primarily by the improved commodity price environment and the increase in the Partnership’s oil production as a percentage of total production.  The average sales price per Mcfe, excluding the impact of realized derivative gains, was $6.06 for the current year period compared to $4.01 for the same period a year ago.  Realized derivative gains from natural gas and oil sales contributed an additional $1.14 per Mcfe or $1.5 million to the first nine months of 2010 total revenues.  Comparatively, the total per Mcfe price realized, consisting of the average sales price and real ized derivative gains, increased to $7.20 for the current year nine months from $6.80 for the same prior year period.

The increase in revenues did not have a corresponding impact on costs and expenses.  Excluding the effect of a $0.2 million accrual for environment remediation costs, natural gas and oil production costs and direct costs−general and administrative combined decreased by $0.4 million for the current year nine months compared to the same prior year period.  The decrease is due to a reduction in volume-associated natural gas and oil production costs and professional fees in the 2010 period compared to the 2009 period.

- 13 -

ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Results of Operations

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

	Three months ended September 30,							Nine months ended September 30,
	2010		2009		Change			2010		2009		Change
Number of producing wells (end of period)		91		91		—			91		91		—
Production (1)
Natural gas (Mcf)		308,621		466,899		-34	%		996,255		1,426,910		-30	%
Oil (Bbl)		18,111		24,299		-25	%		60,085		82,702		-27	%
Natural gas equivalents (Mcfe) (2)		417,287		612,693		-32	%		1,356,765		1,923,122		-29	%
Natural Gas and Oil Sales
Natural gas	$	1,058,780	$	1,228,219		-14	%	$	3,985,587	$	3,706,183		8	%
Oil		1,237,552		1,475,681		-16	%		4,239,326		4,012,194		6	%
Total natural gas and oil sales	$	2,296,332	$	2,703,900		-15	%	$	8,224,913	$	7,718,377		7	%
Realized Gain on Derivatives, net
Natural gas	$	52,712	$	1,016,975		-95	%	$	1,052,288	$	3,980,458		-74	%
Oil		183,164		308,397		-41	%		496,604		1,376,044		-64	%
Total realized gain on derivatives, net	$	235,876	$	1,325,372		-82	%	$	1,548,892	$	5,356,502		-71	%
Average Selling Price (excluding realized gain on derivatives)
Natural gas (per Mcf)	$	3.43	$	2.63		30	%	$	4.00	$	2.60		54	%
Oil (per Bbl)		68.33		60.73		13	%		70.56		48.51		45	%
Natural gas equivalents (per Mcfe)		5.50		4.41		25	%		6.06		4.01		51	%
Average Selling Price (including realized gain on derivatives)
Natural gas (per Mcf)	$	3.60	$	4.81		-25	%	$	5.06	$	5.39		-6	%
Oil (per Bbl)		78.44		73.42		7	%		78.82		65.15		21	%
Natural gas equivalents (per Mcfe)		6.07		6.58		-8	%		7.20		6.80		6	%
Average Lifting Cost (per Mcfe) (3)	$	2.07	$	1.47		41	%	$	1.82	$	1.42		28	%
Operating costs and expenses
Direct costs - general and administrative	$	35,402	$	82,344		-57	%	$	119,072	$	451,902		-74	%
Depreciation, depletion and amortization	$	1,635,865	$	2,220,461		-26	%	$	5,335,507	$	7,115,045		-25	%
Cash distributions	$	1,563,554	$	4,337,169		-64	%	$	6,918,188	$	13,303,848		-48	%

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

(2) A ratio of energy content of natural gas and oil (six Mcf of natural gas equals one Bbl of oil) was used to obtain a conversion factor to convert oil production into equivalent Mcf of natural gas.

(3) Lifting costs represent natural gas and 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

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Natural Gas and Oil Sales

Nine months ended September 30, 2010 as compared to nine months ended September 30, 2009

The $0.5 million, or 7% increase in sales for the 2010 nine month period as compared to the prior year period, was primarily a reflection of the significantly higher average sales price per Mcfe of 51%, which was partially offset by a production volume decrease of 29%.  The average sales price per Mcfe, excluding the impact of realized derivative gains, was $6.06 for the current year nine month period compared to $4.01 for the same period a year ago.

Natural gas and oil revenues increased by 8% and 6%, respectively. The Partnership’s natural gas revenue increase benefited from rising commodity prices per Mcf of 54%, which were partially offset by lower Partnership natural gas production volumes of 30%.  This compares to the more moderate oil revenue increase in which the rise in commodity prices of 45% was partially offset by the more moderate decline in oil production volumes, per Bbl of 27% during the current nine month period.

Three months ended September 30, 2010 as compared to three months ended September 30, 2009

Sales for the 2010 third quarter declined by $0.4 million, or 15% compared to the prior year third quarter.  The decline in quarter-to-quarter Partnership natural gas and oil revenues is primarily a reflection of the higher average sales price per Mcfe of 25%, which was offset by the production volume decrease of 32%.  Average sales prices per Mcfe, excluding the impact of realized derivative gains, were $5.50 for the current year quarter compared to $4.41 for the same quarter a year ago.

The Partnership expects to experience declines in both natural gas and oil production volumes over the wells’ life cycles until such time that the Partnership’s Wattenberg wells may be successfully refraced.  Subsequent to a successful refracturing, production will once again be expected to decline.

Natural Gas and Oil Pricing

Financial results depend upon many factors, particularly the price of natural gas and oil and on PDC’s ability to market the Partnership’s production effectively.  Natural gas and oil prices are among the most volatile of all commodity prices.  This price volatility has a material impact on the Partnership’s financial results.  Natural gas and oil prices also vary by region and locality, depending upon the distance to markets, and the supply and demand relationships in that region or locality and availability of sufficient pipeline capacity.  This can be especially true in the Rocky Mountain Region.  The combination of increased drilling activity and the lack of local markets have resulted in local market oversupply situations from time to time.  Like most p roducers 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 and transportation capacity beyond the Partnership’s control.  Oil pricing, unlike natural gas pricing, is driven predominantly by global supply and demand relationships.

The price at which PDC markets the natural gas produced in the Rocky Mountain Region by the Partnership is based on a variety of prices, which primarily includes natural gas sold at Colorado Interstate Gas, or CIG, prices with a portion sold at Mid-Continent, San Juan Basin, Southern California or other nearby regional prices.  The CIG Index, and other indices for production delivered to Rocky Mountain pipelines, has 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, because of the lack of interstate transmission capacity which moved Rocky Mountain natural gas production to Northeastern U.S. industrial and heating markets.  This negative differential has narrowed in the last year and is lower than historic al variances.  This negative differential between NYMEX and CIG averaged $0.72 and $1.16 for the three and nine months ended September 30, 2009, respectively, and narrowed to an average of $0.51 and $0.88 for the three and nine months ended September 30, 2010, respectively.

- 15 -

ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Commodity Price Risk Management, Net

The Managing General Partner, on behalf of the Partnership in accordance with the D&O Agreement, is authorized to utilize various derivative instruments to manage volatility in natural gas and oil prices.  Commodity price risk management, net, includes realized gains and losses and unrealized changes in the fair value of derivative instruments related to the Partnership’s natural gas and oil production.  The Managing General Partner sets these instruments for PDC, and the various partnerships managed by PDC.  Derivative financial instrument positions taken by the Managing General Partner on the Partnership’s behalf are specifically designated to the Partnership’s production volumes. See Note 4, Fair Value Measurements and Note 5, Derivative Financial Instruments, to the Partnership’s unaudited condensed financial statements included in this report, for additional details on 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 (loss), net.

	Three months ended September 30,						Nine months ended September 30,
	2010			2009			2010			2009
Commodity price risk management gain (loss), net
Realized gains
Natural Gas	$	52,712		$	1,016,975		$	1,052,288		$	3,980,458
Oil		183,164			308,397			496,604			1,376,044
Total realized gain, net		235,876			1,325,372			1,548,892			5,356,502
Unrealized gains (losses)
Reclassification of realized gains included in prior periods unrealized		(112,014	)		(1,328,325	)		(383,673	)		(4,352,668	)
Unrealized gain (loss) for the period		1,652,801			(1,308,968	)		4,057,884			(4,240,353	)
Total unrealized gain (loss), net		1,540,787			(2,637,293	)		3,674,211			(8,593,021	)
Commodity price risk management gain (loss), net	$	1,776,663		$	(1,311,921	)	$	5,223,103		$	(3,236,519	)

Nine months ended September 30, 2010 as compared to nine months ended September 30, 2009

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 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 the Partnership's commodity positions 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 oil forward curves, offset by unrealized losses due to the basis differential between NYMEX and CIG being na rrower 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 by unrealized losses on the Partnership's basis position of $0.3 million.

For the 2009 nine month period, the Partnership realized significant derivative gains as a result of lower natural gas and oil prices at settlement compared to the respective derivative strike prices.  Unrealized losses for the period were related to oil swaps, as the forward strip price of oil rebounded during the period, and the CIG basis swaps, as the forward basis differential during the period between NYMEX and CIG continued to narrow from the strike price of the derivative position.

Three months ended September 30, 2010 as compared to three months ended September 30, 2009

The realized derivative gains for the 2010 third quarter were approximately $0.2 million.  These realized gains are a result of lower natural gas and 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 the Partnership's commodity positions 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 $1.6 million were primarily related to the oil positions, as the forward strip price shifted downward during the quarter, and the widening of the NYMEX-CIG basis differential.  Unrealized gains on the Partnership’s commodity positions for the 2010 third quarter were $1.8 million offset by unrealized losses on the Partnerships basis position of $0.2 million.

- 16 -

ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

For the 2009 third quarter, the Partnership realized significant derivative gains as a result of lower natural gas and oil prices at settlement compared to the respective derivative strike prices.  Unrealized losses for the period were primarily related to oil swaps, as the forward strip price of oil rebounded during the period, and the CIG basis swaps, as the forward basis differential during the period between NYMEX and CIG continued to narrow from the strike price of the derivative position.

Natural Gas and Oil Sales Derivative Instruments.  The Managing General Partner, on behalf of the Partnership in accordance with the D&O Agreement, is authorized to utilize various derivative instruments to manage volatility in natural gas and oil prices.  The Partnership has in place a series of collars, fixed-price swaps and a basis swap on a portion of the Partnership’s natural gas and oil production.  See Note 5, Derivative Financial Instruments to the Partnership’s financial statements included in the 2009 Form 10-K for an additional discussion on how each derivative type impacts the Partnership’s cash flows.

The following table presents the Partnership’s derivative positions in effect as of September 30, 2010.

	Collars						Fixed-Price Swaps				CIG Basis Protection Swaps
Commodity/	Quantity (Gas-		Weighted Average Contract Price				Quantity (Gas-Mmbtu		Weighted Average Contract		Quantity (Gas-		Weighted Average Contract			Fair Value at September 30,
Index	Mmbtu)(1)		Floors		Ceilings		Oil-Bbls)(1)		Price		Mmbtu)(1)		Price			2010(2)
Natural Gas
CIG													��
10/01 - 12/31/2010		79,402	$	4.75	$	9.45		—	$	—		—	$	—		$	88,439
01/01 - 03/31/2011		119,103		4.75		9.45		—		—		—		—			110,537
NYMEX
10/01 - 12/31/2010		30,275		5.75		8.30		160,106		6.08		188,334		(1.88	)		131,478
01/01 - 03/31/2011		40,636		5.75		8.30		88,494		6.82		129,130		(1.88	)		96,354
04/01 - 06/30/2011		—		—		—		244,395		6.78		244,395		(1.88	)		290,929
07/01 - 09/30/2011		—		—		—		238,556		6.73		238,556		(1.88	)		234,029
10/01 - 12/31/2011		—		—		—		230,090		6.78		230,090		(1.88	)		144,708
2012-2013		55,443		6.00		8.27		1,558,232		7.05		1,613,677		(1.88	)		809,037
Total Natural Gas		324,859						2,519,873				2,644,182					1,905,511
Oil
NYMEX
10/01 - 12/31/2010		—		—		—		10,934		92.96		—		—			127,772
01/01 - 03/31/2011		—		—		—		4,882		70.75		—		—			(58,567	)
04/01 - 06/30/2011		—		—		—		4,894		70.75		—		—			(64,054	)
07/01 - 09/30/2011		—		—		—		4,907		70.75		—		—			(68,122	)
10/01 - 12/31/2011		—		—		—		4,871		70.75		—		—			(70,897	)
Total Oil		—						30,488				—					(133,868	)
Total Natural Gas and Oil																$	1,771,643

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

(2) Approximately 9% of the fair value of the Partnership’s derivative assets and all of the Partnership’s derivative liabilities were measured using significant unobservable inputs (Level 3), see Note 4, Fair Value Measurements, to the accompanying unaudited condensed financial statements included in this report.

Natural Gas and Oil Production Costs

Generally, natural gas and oil production costs vary with changes in total natural gas and 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 and 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 expect ed 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.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Nine months ended September 30, 2010 as compared to nine months ended September 30, 2009

For the nine months ended September 30, 2010 compared to the same period in 2009, natural gas and oil production, on an energy equivalency-basis, decreased 29%, which reflects in part, the normally-occurring production declines throughout a natural gas and oil well’s production life cycle.  Additionally, Grand Valley Field well equipment constraints, requiring well workovers of five wells, as well as Wattenberg Field operational constraints on most wells during the first half of 2010, also contributed to the production decline during the current period.

Production and operating costs were lower by approximately $0.3 million or 10%, due in part, to volume-associated reductions in production taxes, natural gas transportation and lease operating expenses.  Partially offsetting the production volume-associated cost reductions were higher lease operating expenses of approximately $0.3 million related to 13 well workovers performed during the period and by the accrual of 2010 environmental remediation costs of approximately $0.2 million.  Additionally, the downward adjustment to the Partnership’s accrued production-related taxes due to revisions to tax rates by the Colorado tax agencies, further reduced production costs during the nine-month period.   Production and operating costs per Mcfe rose to $1.82 during the current year nine months compared to $1.42 for the prior year nine months due to the effect of lower per-volume related natural gas and oil production costs offset by higher per-well related expenditures.

Three months ended September 30, 2010 as compared to three months ended September 30, 2009

For the quarter ended September 30, 2010 compared to the same period in 2009, natural gas and oil production, on an energy equivalency-basis, decreased 32%, primarily as a result of the Partnership wells’ reduced performance noted above and expected normally-occurring production life-cycle decline in both operating fields.

Production and operating costs were unchanged at $0.9 million during the 2010 quarter and 2009 quarters, respectively, primarily due to higher lease operating expenses of approximately $0.2 million, as a result of nine well workovers conducted during the quarter, which were offset by volume-associated reductions in production taxes, natural gas transportation and lease operating expenses.  Production and operating costs per Mcfe rose to $2.07 during the current quarter compared to $1.47 for the prior year quarter due to the effect of lower per-volume related natural gas and oil production costs offset by higher per-well related expenditures.

Direct Costs−General and Administrative

Nine months ended September 30, 2010 as compared to nine months ended September 30, 2009

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 decreased during the nine months ended September 30, 2010, compared to the same period in 2009, by approximately $0.3 million principally due to reduced billings for professional services.

Three months ended September 30, 2010 as compared to three months ended September 30, 2009

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 decreased during the three months ended September 30, 2010, compared to the same period in 2009, by approximately $47,000 principally due to reduced billings for professional services.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Depreciation, Depletion and Amortization

DD&A expense related to natural gas and oil properties is directly related to production volumes for the period.  For the quarter ended September 30, 2009, the Partnership’s natural gas and oil economically producible reserve quantities were determined by valuing in-ground natural gas and oil resources, at the price of natural gas and oil as of December 31, 2008.  Upon adoption, in the fourth quarter of 2009, of the SEC’s final rule regarding the modernization of oil and gas reporting, the Partnership changed to a valuation price determined by the 12-month average of the first-day-of-the-month price during each month of 2009.

Nine months ended September 30, 2010 as compared to nine months ended September 30, 2009

The DD&A expense rate per Mcfe increased to $3.93 for the 2010 nine month period, compared to $3.70 during the same period in 2009, as calculated by the respective methodologies described above.  The increase in the per Mcfe rates for the 2010 period compared to the 2009 period is primarily the result of the changing production mix among the Partnership’s Wattenberg, Grand Valley and North Dakota fields, which have significantly different DD&A rates.  The field-level depletion rate increased due to the effects of reserve revisions at December 31, 2009 compared to December 31, 2008 in which proved developed producing downward revisions in the Partnership’s Grand Valley Field were partially offset by upward proved develop ed producing revisions in its Wattenberg and North Dakota fields.  The effect of the production declines noted in previous sections, partially offset by the increased DD&A expense rate, resulted in the DD&A expense reduction of approximately $1.8 million for the 2010 nine month period compared to the same 2009 period.

Three months ended September 30, 2010 as compared to three months ended September 30, 2009

The DD&A expense rate per Mcfe increased to $3.92 for the 2010 third quarter, compared to $3.62 during the same quarter in 2009 as calculated by the respective methodologies described above.  The increase in the per Mcfe rates for the 2010 third quarter compared to the 2009 third quarter is a result of the combined effects of the changing production mix among fields and changes in field-level depletion rates, noted above.  The effect of the production declines noted in previous sections, partially offset by the increased DD&A expense rate, resulted in the DD&A expense reduction of $0.6 million for the 2010 third quarter compared to the same 2009 quarter.

Capital Resources and Liquidity

The Partnership’s primary sources of cash for both the three and the nine months ended September 30, 2010 were from funds provided by operating activities which include the sale of natural gas and oil production and the realized gains from the Partnership’s derivative positions.  These sources of cash were primarily used to fund the Partnership’s operating costs, general and administrative activities and provide monthly distributions to the Investor Partners and PDC, the Managing General Partner.  Fluctuations in the Partnership’s operating cash flow are substantially driven by changes in commodity prices, in production volumes and in realized gains and losses from commodity positions.  Commodity prices ha ve historically been volatile and the Partnership 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 and oil sales and realized derivative gains and losses.  However, the Partnership does not engage in speculative positions, nor does the Partnership hold economic hedges 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, 2010, the Partnership had natural gas and oil derivative positions in place covering 73% of the expected natural gas production and 59% of expected oil production for the remainder of 2010, at an average price of $4.34 per Mcf and $92.96 per Bbl, respectively.  The Partnership’s current derivative position average prices have declined from the signif icantly higher average commodity contract strike price levels in effect during the 2009 comparative period, which were the result of contracts entered into during the high 2008 commodity price market; accordingly, the Partnership anticipates realized gains for the next 12 months to remain substantially below gains realized in 2009 and the first quarter of 2010.  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.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

The Partnership’s future operations are expected to be conducted with available funds and revenues generated from natural gas and oil production activities and commodity gains, if any.  Natural gas and oil production from the Partnership’s existing properties are generally expected to continue a gradual decline in the rate of production over the remaining lives of the wells.  Therefore, the Partnership anticipates a lower annual level of natural gas and oil production and, in the absence of significant price increases or successful refracturings, 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 t hese circumstances decreased production would have a material negative impact on the Partnership’s operations and may result in reduced cash distributions to the Investor Partners through the remainder of 2010 and beyond, and may substantially reduce or restrict the Partnership’s ability to participate in the Well Refracturing Plan activities which are more fully described in Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations−Well Refracturing Plan.  Although there are no current plans by the Managing General Partner to utilize the Partnership’s borrowing capability to fund Partnership’s Codell formation refracturing activities, should borrowing be elected in the future, potential distributable cash flows derived from production increases provided by the further development of the Partnership’s Wattenberg Field w ells may not be sufficient to repay the Partnership’s borrowing financial obligations, which would include principal and interest.

Working Capital

The Partnership had working capital of $2.4 million at September 30, 2010 compared to working capital of $1.6 million at December 31, 2009.  This increase of approximately $0.8 million was primarily due to the following changes in accounts receivable and payable balances:

● Cash and cash equivalents increased by $0.3 million as of September 30, 2010 compared to December 31, 2009.

● Natural gas and oil receivables decreased by $0.6 million as of September 30, 2010 compared to December 31, 2009.

● Realized derivative gains receivables decreased by $0.7 million as of September 30, 2010 compared to December 31, 2009.

● Net short-term unrealized derivative gains receivable increased by approximately $0.7 million as of September 30, 2010 compared to December 31, 2009.

● Accounts payable and accrued expenses increased by $0.1 million as of September 30, 2010, compared to December 31, 2009, primarily due to the environmental remediation accrual.

● Due to the Managing General Partner-other payable, excluding natural gas and oil sales received from third parties and realized derivative gains, decreased by approximately $1.2 million as of September 30, 2010 compared to December 31, 2009.

Working capital, primarily cash and cash equivalents, is expected to increase during early 2011 due to the Partnership’s withholding cash from the investors for the initial Wattenberg Field well refracturing activities.  Cash will begin to decrease as the funds are utilized in payment of the completed refracturing activities, currently planned to occur during mid-to-late 2011. Funding for the Well Refracturing Plan will be provided by the withholding of distributable cash flows from the Managing General Partner and Investor Partners on a pro-rata basis. Working capital is expected to similarly fluctuate by increasing during periods of Well Refracturing Plan funding and by decreasing during periods when payments are made for completed well refracturing.

Cash Flows

Cash Flows From Investing Activities

The Partnership, from time-to-time, invests in additional equipment which supports treatment, delivery and measurement of natural gas and oil or environmental protection.  These amounts totaled approximately $0.1 million and $0.2 million for the nine months ended September 30, 2010 and 2009, respectively. During the nine months ended September 30, 2010, the Partnership paid to the Managing General Partner through the retention of distributable cash flows, $1,068,657 for additional drilling costs incurred in 2008, which were in excess of drilling advances paid to the Managing General Partner in 2006.  During 2009, the Partnership realized proceeds of a State of Colorado sales tax refund of $50,000 and sale of surplus equipment of $40,000
60;which were treated as a reduction to the Partnership’s capitalized “Oil and gas properties.”

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Cash Flows From Financing Activities

The Partnership initiated monthly cash distributions to investors in May 2007 and has distributed $69.5 million through September 30, 2010.  The table below presents the cash distributions to the Managing General Partner and Investor Partners, including Managing General Partner distributions relating to limited partnership units repurchased, for the periods described.

Three months ended September 30,	Managing General Partner Distributions		Investor Partners Distributions		Total Distributions
2010	$	578,515	$	985,039	$	1,563,554
2009	$	1,604,753	$	2,732,416	$	4,337,169

Nine months ended September 30,	Managing General Partner Distributions		Investor Partners Distributions		Total Distributions
2010	$	2,559,730	$	4,358,458	$	6,918,188
2009	$	4,922,421	$	8,381,427	$	13,303,848

The Partnership began funding for the Well Refracturing Plan during October 2010.  On a pro-rata basis based on percentage of ownership in the Partnership, the Partnership withheld $7,400 and $12,600, respectively, from the Managing General Partner and Investor Partners’ share of distributable cash flows from the Partnership’s August 2010 natural gas and oil revenues distributed in October 2010.  The October 2010 and subsequent withholdings will provide the funding for planned Wattenberg Field well refracturing costs to be incurred during 2011, and thereafter.

Cash Flows From Operating Activities

Net cash provided by operating activities was $8.4 million for the nine months ended September 30, 2010, compared to approximately $13.2 million for the comparable period in 2009.  The approximately $4.8 million decrease in cash provided by operating activities was due primarily to the following:

● A decrease in natural gas and oil production costs of approximately $0.3 million, or 10%, accompanied by a decrease in direct costs – general and administrative of $0.3 million, or 74%;

● A decrease in natural gas and oil sales receipts of $0.8 million, or 8%, accompanied by a decrease in commodity price risk management realized gains receipts of $4.4 million, or 66%;

● A decrease in accounts payable−accrued expenses payments of $0.1 million; and

● An increase in Due to Managing General Partner-other, net, payments of approximately $0.3 million, excluding natural gas and oil sales received from third parties and realized derivative gains.

At this time, no bank borrowings or significant advances by the Managing General Partner are anticipated in order to fund the Partnership’s initial Wattenberg Field Codell formation well refracturing activity, which is expected to occur in mid-to-late 2011. Future borrowings, if any, will be non-recourse to the Investor Partners; accordingly, the Partnership, not the Investor Partners, will be responsible for repaying the loan.  However, any bank borrowings may be collateralized by the Partnership’s assets.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Commitments and Contingencies

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

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 other 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 2009 Form 10-K, such policies include revenue recognition, derivatives instruments, fair value measurements, natural gas and oil properties, and asset retirement obligations are based on, among other things, judgments and assumptions made by management that include inherent risks and uncertainties.

Off-Balance Sheet Arrangements

Currently, the Partnership does not have any off-balance sheet arrangements.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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, 2010, PDC, as Managing General Partner 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 Securities Exchange Act Rule 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 we file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified by the SEC̵ 7;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 financial 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, 2010.

(b) Changes in Internal Control over Financial Reporting

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 Securities Exchange Act of 1934) during the quarter ended September 30, 2010, that have materially affected or are reasonably likely to materially affect the Partnership’s internal control over financial reporting.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

Information regarding the Registrant’s legal proceedings can be found in Note 6, Commitments and Contingencies, to the Partnership’s accompanying unaudited condensed financial statements.

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 reque st 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.

Period	Total Number of Units Repurchased		Average Price Paid per Unit
July 1—31, 2010		—	$	—
August 1—31, 2010		—		—
September 1—30, 2010		5.00		6,139
Total third quarter Unit Repurchase Program repurchases		5.00

Item 3.  Defaults Upon Senior Securities

Not applicable.

Item 4. [Removed and Reserved]

Item 5. Other Information

Not applicable.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Item 6. Exhibits

(a)       Exhibit Index.

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	SEC File Number	Exhibit	Filing Date	Filed Herewith

3.1	Limited Partnership Agreement	10-12G/A Amend 1	000-52787	3	12/24/2007
3.2	Certificate of limited partnership which reflects the organization of the Partnership under West Virginia law	10-12G/A Amend 1	000-52787	3.1	12/24/2007
10.1	Drilling and operating agreement between the Partnership and Petroleum Development Corporation (dba PDC Energy), as Managing General Partner.	10-12G/A Amend 1	000-52787	10.2	12/24/2007
10.2	Form of assignment of leases to the Partnership	10-12G/A Amend 1	000-52787	10.1	12/24/2007
10.4	Gas Purchase and Processing Agreement between Duke Energy Field Services, Inc.; United States Exploration, Inc.; and Petroleum Development Corporation, dated October 28, 1999 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)	10-12G/A Amend 3	000-53201	10.3	03/31/2009
10.5	Gas Purchase and Processing Agreement between Natural Gas Associates, a Colorado partnership, and Aceite Energy Corporation, Walker Exploratory Program 1982-A Limited and Cattle Creek Company, dated October 14, 1983 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)	10-12G/A Amend 3	000-53201	10.4	03/31/2009
10.6	Gas Purchase and Processing Agreement between Natural Gas Associates, a Colorado partnership, and SHF Partnership, a Colorado general partnership, Trailblazer Oil and Gas, Inc., Alfa Resources, Inc., Pulsar Oil and Gas, Inc., Overthrust Oil Royalty Corporation, Corvette Petroleum Ltd., Robert Lanari, an individual, and Toby A Martinez, an individual, dated September 21, 1983 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)	10-12G/A Amend 3	000-53201	10.5	03/31/2009

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	SEC File Number	Exhibit	Filing Date	Filed Herewith

10.7	Domestic Crude Oil Purchase Agreement with ConocoPhillips Company, dated January 1, 1993, as amended by agreements with Teppco Crude Oil, LLC dated August 2, 2007; September 24, 2007; October 17, 2007; January 7, 2008; January 15, 2008; and April 17, 2008 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)	10-12G/A Amend 3	000-53201	10.6	03/31/2009
10.8	Gas Purchase Agreement between Williams Production RMT Company, Riley Natural Gas Company and Petroleum Development Corporation, dated as of June 1, 2006 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)	10-12G/A Amend 3	000-53201	10.7	03/31/2009
10.9	Domestic Crude Oil Purchase Agreement between Suncor Energy Marketing Inc. and Petroleum Development Corporation, dated April 22, 2008	10-Q	000-52787	10.1	05/18/2009
10.10	Domestic Crude Oil Purchase Agreement between Shell Trading (US) Company and Petroleum Development Corporation, dated September 13, 2007	10-K	000-52787	10.9	03/31/2009
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.					X
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.					X

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	SEC File Number	Exhibit	Filing Date	Filed Herewith

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 Sarbanes-Oxley Act of 2002. X

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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/ Richard W. McCullough
Richard W. McCullough Chairman and Chief Executive Officer of Petroleum Development Corporation (dba PDC Energy)
November 5, 2010

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/ Richard W. McCullough	Chairman and Chief Executive Officer	November 5, 2010
Richard W. McCullough	Petroleum Development Corporation (dba PDC Energy)
	Managing General Partner of the Registrant
	(Principal executive officer)
/s/ Gysle R. Shellum	Chief Financial Officer	November 5, 2010
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 5, 2010
R. Scott Meyers	Petroleum Development Corporation (dba PDC Energy)
	Managing General Partner of the Registrant
	(Principal accounting officer)

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