Attached files
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
WASHINGTON,
DC 20549
FORM
10-Q
T QUARTERLY
REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
For
the quarterly period ended September 30, 2009
or
£ 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 and (2) has been subject to such filing requirements for the
past 90 days.
Yes T 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 £ 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 definition 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 T
|
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act). Yes £ No
T
As of
October 31, 2009, 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
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PART
I – FINANCIAL INFORMATION
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Item
1.
|
Condensed
Financial Statements (unaudited)
|
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1
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2
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3
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4
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Item
2.
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15
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Item
3.
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25
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Item
4T.
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25
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PART
II – OTHER INFORMATION
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Item
1.
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27
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Item
1A.
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27
|
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Item
2.
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27
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Item
3.
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27
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Item
4.
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27
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Item
5.
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27
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Item
6.
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28
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29
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PART
I – FINANCIAL INFORMATION
Item
1.
|
Condensed
Financial Statements (unaudited)
|
Rockies Region 2006 Limited Partnership
Condensed
Balance Sheets
(unaudited)
September 30,
|
December 31,
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|||||||
2009
|
2008*
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|||||||
Assets
|
||||||||
Current
assets:
|
||||||||
Cash
and cash equivalents
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$ | 5,307 | $ | 203,462 | ||||
Accounts
receivable
|
739,669 | 1,173,324 | ||||||
Oil
inventory
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36,062 | 45,750 | ||||||
Due
from Managing General Partner-derivatives
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2,713,191 | 5,772,399 | ||||||
Due
from Managing General Partner-other, net
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- | 2,372,921 | ||||||
Total
current assets
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3,494,229 | 9,567,856 | ||||||
Oil
and gas properties, successful efforts method, at cost
|
97,653,671 | 97,606,701 | ||||||
Less: Accumulated
depreciation, depletion and amortization
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(32,821,440 | ) | (25,706,395 | ) | ||||
Oil
and gas properties, net
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64,832,231 | 71,900,306 | ||||||
Due
from Managing General Partner-derivatives
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194,830 | 2,009,629 | ||||||
Total
noncurrent assets
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65,027,061 | 73,909,935 | ||||||
Total
Assets
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$ | 68,521,290 | $ | 83,477,791 | ||||
Liabilities and Partners'
Equity
|
||||||||
Current
liabilities:
|
||||||||
Accounts
payable and accrued expenses
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$ | 104,290 | $ | 206,320 | ||||
Due
to Managing General Partner-derivatives
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1,035,912 | - | ||||||
Due
to Managing General Partner-other, net
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591,353 | - | ||||||
Total
current liabilities
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1,731,555 | 206,320 | ||||||
Due
to Managing General Partner-derivatives
|
2,983,512 | 300,410 | ||||||
Asset
retirement obligations
|
805,500 | 775,083 | ||||||
Total
liabilities
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5,520,567 | 1,281,813 | ||||||
Commitments
and contingent liabilities
|
||||||||
Partners'
equity:
|
||||||||
Managing
General Partner
|
18,374,253 | 25,476,495 | ||||||
Limited
Partners - 4,497.03 units issued and outstanding
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44,626,470 | 56,719,483 | ||||||
Total
Partners' equity
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63,000,723 | 82,195,978 | ||||||
Total
Liabilities and Partners' Equity
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$ | 68,521,290 | $ | 83,477,791 |
*Derived
from audited December 31, 2008 balance sheet contained in the Partnership’s Form
10-K for the year ended December 31, 2008.
See
accompanying notes to unaudited condensed financial statements.
Rockies Region 2006 Limited Partnership
Condensed
Statements of Operations
(unaudited)
Three months ended
September 30,
|
Nine months ended
September 30,
|
|||||||||||||||
2009
|
2008
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2009
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2008
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|||||||||||||
Revenues:
|
||||||||||||||||
Oil
and gas sales
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$ | 2,703,900 | $ | 7,890,247 | $ | 7,718,377 | $ | 26,486,935 | ||||||||
Oil
and gas price risk management (loss) gain, net
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(1,311,921 | ) | 11,036,114 | (3,236,519 | ) | 2,175,761 | ||||||||||
Total
revenues
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1,391,979 | 18,926,361 | 4,481,858 | 28,662,696 | ||||||||||||
Operating
costs and expenses:
|
||||||||||||||||
Production
and operating costs
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902,587 | 1,433,870 | 2,740,184 | 4,656,025 | ||||||||||||
Direct
costs - general and administrative
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82,344 | 177,233 | 451,902 | 552,978 | ||||||||||||
Depreciation,
depletion and amortization
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2,220,461 | 2,560,044 | 7,115,045 | 8,327,128 | ||||||||||||
Exploratory
dry hole costs
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37,162 | 35,737 | 37,243 | 84,268 | ||||||||||||
Accretion
of asset retirement obligations
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10,139 | 9,635 | 30,417 | 28,727 | ||||||||||||
Total
operating costs and expenses
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3,252,693 | 4,216,519 | 10,374,791 | 13,649,126 | ||||||||||||
(Loss)
income from operations
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(1,860,714 | ) | 14,709,842 | (5,892,933 | ) | 15,013,570 | ||||||||||
Gain
on sale of leasehold
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- | - | - | 120,000 | ||||||||||||
Interest
expense
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(5,892 | ) | - | (5,892 | ) | - | ||||||||||
Interest
income
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- | 13,162 | 7,418 | 73,033 | ||||||||||||
Net
(loss) income
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$ | (1,866,606 | ) | $ | 14,723,004 | $ | (5,891,407 | ) | $ | 15,206,603 | ||||||
Net
(loss) income allocated to partners
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$ | (1,866,606 | ) | $ | 14,723,004 | $ | (5,891,407 | ) | $ | 15,206,603 | ||||||
Less: Managing
General Partner interest in net (loss) income
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(690,645 | ) | 5,447,511 | (2,179,821 | ) | 5,626,443 | ||||||||||
Net
(loss) income allocated to Investor Partners
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$ | (1,175,961 | ) | $ | 9,275,493 | $ | (3,711,586 | ) | $ | 9,580,160 | ||||||
Net
(loss) income per Investor Partner unit
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$ | (261 | ) | $ | 2,063 | $ | (825 | ) | $ | 2,130 | ||||||
Investor
Partner units outstanding
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4,497.03 | 4,497.03 | 4,497.03 | 4,497.03 |
See
accompanying notes to unaudited condensed financial statements.
Rockies Region 2006 Limited Partnership
Condensed
Statements of Cash Flows
(unaudited)
Nine months ended
September 30,
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||||||||
2009
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2008
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Cash
flows from operating activities:
|
||||||||
Net
(loss) income
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$ | (5,891,407 | ) | $ | 15,206,603 | |||
Adjustments
to reconcile net (loss) income to net cash provided by operating
activities:
|
||||||||
Depreciation,
depletion and amortization
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7,115,045 | 8,327,128 | ||||||
Accretion
of asset retirement obligations
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30,417 | 28,727 | ||||||
Unrealized
loss (gain) on derivative transactions
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8,593,021 | (3,695,355 | ) | |||||
Exploratory
dry hole costs
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37,243 | 84,268 | ||||||
Gain
on sale of leasehold
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- | (120,000 | ) | |||||
Changes
in operating assets and liabilities:
|
||||||||
Decrease
in accounts receivable
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433,655 | 1,517,831 | ||||||
Decrease
(increase) in oil inventory
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9,688 | (50,739 | ) | |||||
Decrease
in other assets
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- | 40,000 | ||||||
Decrease
in accounts payable and accrued expenses
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(102,030 | ) | (76,094 | ) | ||||
Decrease
(increase) in due from Managing General Partner - other,
net
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2,372,921 | (814,273 | ) | |||||
Increase
in due to Managing General Partner - other, net
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591,353 | - | ||||||
Net
cash provided by operating activities
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13,189,906 | 20,448,096 | ||||||
Cash
flows from investing activities:
|
||||||||
Capital
expenditures for oil and gas properties
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(174,308 | ) | (1,131,636 | ) | ||||
Proceeds
from sale of leaseholds
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- | 120,000 | ||||||
Proceeds
from sale of equipment
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40,048 | - | ||||||
Proceeds
from Colorado sales tax refund related to capital
purchases
|
50,047 | - | ||||||
Net
cash used in investing activities
|
(84,213 | ) | (1,011,636 | ) | ||||
Cash
flows from financing activities:
|
||||||||
Distributions
to Partners
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(13,303,848 | ) | (20,425,483 | ) | ||||
Net
cash used in financing activities
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(13,303,848 | ) | (20,425,483 | ) | ||||
Net
decrease in cash and cash equivalents
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(198,155 | ) | (989,023 | ) | ||||
Cash
and cash equivalents, beginning of period
|
203,462 | 1,183,810 | ||||||
Cash
and cash equivalents, end of period
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$ | 5,307 | $ | 194,787 | ||||
Supplemental
disclosure of non-cash activity:
|
||||||||
Asset
retirement obligation, with corresponding change to oil and gas
properties
|
$ | - | $ | (4,006 | ) |
See
accompanying notes to unaudited condensed financial statements.
ROCKIES REGION 2006 LIMITED PARTNERSHIP
NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS
September
30, 2009
(unaudited)
Note
1−General and Basis of
Presentation
The
Rockies Region 2006 Limited Partnership (the “Partnership” or the “Registrant”)
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 sale of Partnership units on September 7, 2006 (date of
inception), the Partnership was funded and commenced its business
operations. The Partnership owns natural gas and oil wells located in
Colorado and North Dakota, 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, is the Managing General Partner of the Partnership
(hereafter, the “Managing General Partner,” “MGP” 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. 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, 2009, there were 2,022 Investor Partners. As Managing
General Partner, PDC has repurchased 5.5 units of the total 4,497.03 outstanding
units of Partnership interests from Investor Partners at an average price of
$11,985 per unit through September 30, 2009 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
accompanying interim unaudited condensed financial statements have been prepared
without audit in accordance with accounting principles generally accepted in the
United States of America, or U.S., for interim financial information and with
the instructions to Form 10-Q and Article 8 of Regulation S-X of the Securities
and Exchange Commission, or SEC. Accordingly, pursuant to certain rules and
regulations, certain notes and other financial information included in audited
financial statements have been condensed or omitted. In the
Partnership’s opinion, the accompanying interim unaudited condensed financial
statements contain all adjustments (consisting of only normal recurring
adjustments) necessary to present fairly the Partnership's financial position,
results of operations and cash flows for the periods presented. The
interim results of operations and cash flows for the nine months ended September
30, 2009 and 2008 are not necessarily indicative of the results to be expected
for the full year or any other future period.
The
accompanying interim unaudited condensed financial statements should be read in
conjunction with the audited financial statements and notes thereto included in
the Partnership's Form 10-K for the year ended December 31, 2008, as filed with
the SEC on March 31, 2009 (“the 2008 Form 10-K”).
Reclassifications
Certain
amounts in the prior period have been reclassified to conform with the current
year classifications with no effect on previously reported net income or
Partners’ equity. For more information on these reclassifications,
see Note 3, −Transactions with
Managing General Partner and Affiliates.
ROCKIES
REGION 2006 LIMITED PARTNERSHIP
NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS
September
30, 2009
(unaudited)
Note
2−Recent Accounting
Standards
Recently Adopted Accounting
Standards
Accounting
Standards Codification
In June
2009, the Financial Accounting Standards Board, or FASB, issued the FASB
Accounting Standards Codification™ (the “Codification”), thereby establishing
the Codification as the source of authoritative accounting principles recognized
by the FASB to be applied by nongovernmental entities in the preparation of
financial statements in conformity with U.S. Generally Accepted Accounting
Principles, or GAAP. Rules and interpretive releases of the SEC under
authority of federal securities laws are also sources of authoritative GAAP for
SEC registrants. The FASB will no longer issue new standards in the
form of Statements, FASB Staff Positions, or Emerging Issues Task Force
Abstracts; instead, the FASB will issue Accounting Standards
Updates. Accounting Standards Updates will not be authoritative in
their own right as they will only serve to update the
Codification. These changes and the Codification itself do not change
GAAP. Effective July 1, 2009, the Partnership adopted the
Codification. Other than the manner in which new accounting guidance
is referenced, the adoption of the Codification did not have any impact on the
Partnership’s accompanying interim unaudited condensed financial
statements.
Subsequent
Events
In May
2009, the FASB issued changes regarding subsequent events, which establishes
general standards of accounting for and disclosure of events that occur after
the balance sheet date but before financial statements are issued. Specifically,
the guidance sets forth the period after the balance sheet date during which the
Managing General Partner should evaluate events or transactions that may occur
for potential recognition or disclosure in the Partnership’s financial
statements, the circumstances under which the Partnership should recognize
events or transactions occurring after the balance sheet date in the
Partnership’s financial statements, and the disclosures that the Partnership
should make about events or transactions that occurred after the balance sheet
date. The Partnership adopted the guidance as of June 30, 2009. See Note 7,
Subsequent
Events.
Business
Combinations
In
December 2007, the FASB issued changes regarding the accounting for business
combinations. The new changes require:
|
·
|
an
acquirer to recognize the assets acquired, the liabilities assumed and any
noncontrolling interest in the acquiree at their acquisition-date fair
values;
|
|
·
|
disclosure
of the information necessary for investors and other users to evaluate and
understand the nature and financial effect of the business
combination;
|
|
·
|
acquisition-related
costs be expensed as incurred.
|
The
changes also amend the accounting for income taxes to require the acquirer to
recognize changes in the amount of its deferred tax benefits recognizable due to
a business combination either in income from continuing operations in the period
of the combination or directly in contributed capital, depending on the
circumstances. Further, the changes amend the accounting for income taxes to
require, subsequent to a prescribed measurement period, changes to
acquisition-date income tax uncertainties to be reported in income from
continuing operations and changes to acquisition-date acquiree deferred tax
benefits to be reported in income from continuing operations or directly in
contributed capital, depending on the circumstances.
ROCKIES
REGION 2006 LIMITED PARTNERSHIP
NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS
September
30, 2009
(unaudited)
In April
2009, the FASB again issued changes to the accounting for business
combinations. These changes apply to all assets acquired and
liabilities assumed in a business combination that arise from contingencies and
require:
|
·
|
an
acquirer to recognize at fair value, at the acquisition date, an asset
acquired or liability assumed in a business combination that arises from a
contingency if the acquisition-date fair value of that asset or liability
can be determined during the measurement period otherwise the asset or
liability should be recognized at the acquisition date if certain defined
criteria are met;
|
|
·
|
contingent
consideration arrangements of an acquiree assumed by the acquirer in a
business combination be recognized initially at fair
value;
|
|
·
|
subsequent
measurements of assets and liabilities arising from contingencies be based
on a systematic and rational method depending on their nature and
contingent consideration arrangements be measured subsequently;
and
|
|
·
|
disclosures
of the amounts and measurements basis of such assets and liabilities and
the nature of the contingencies.
|
The
changes above became effective for acquisitions completed on or after January 1,
2009; however, the income tax changes became effective as of that date for all
acquisitions, regardless of the acquisition date. The Partnership adopted these
changes effective January 1, 2009, for which they will be applied prospectively
in the Partnership’s accounting for future acquisitions, if any. This
adoption had no impact on the Partnership’s accompanying interim unaudited
condensed financial statements.
Consolidation
– Noncontrolling Interest in a Subsidiary
In
December 2007, the FASB issued changes regarding the nature and classification
of the noncontrolling interest in a subsidiary in the consolidated financial
statements. The changes require the accounting and reporting for minority
interests be recharacterized as noncontrolling interests and classified as a
component of equity. Additionally, the changes establish reporting requirements
that provide sufficient disclosures which clearly identify and distinguish
between the interests of the parent and the interests of the noncontrolling
owners. The Partnership adopted these changes effective January 1,
2009. The Partnership’s adoption of this guidance had no material
impact on the Partnership’s accompanying interim unaudited condensed financial
statements.
Fair
Value Measurements and Disclosures
In
February 2008, the FASB delayed by one year (to January 1, 2009) the fair value
measurements and disclosure requirements for nonfinancial assets and
liabilities, except those that are recognized or disclosed at fair value in the
financial statements on a recurring basis (at least annually). The January 1,
2009, adoption of the fair value measurements and disclosure requirements for
the Partnership’s nonfinancial assets and liabilities did not have a material
impact on the Partnership’s accompanying interim unaudited condensed financial
statements. See Note 4, Fair
Value Measurements.
Derivatives
and Hedging Disclosures
In March
2008, the FASB issued changes regarding the disclosure requirements for
derivative instruments and hedging activities. Pursuant to the
changes, enhanced disclosures are required to provide information about (a) how
and why the Partnership uses derivative instruments, (b) how the Partnership
accounts for derivative instruments and related hedged items and (c) how
derivative instruments and related hedged items affect the Partnership’s
financial position, financial performance and cash flows. The
Partnership adopted these changes effective January 1, 2009. The
adoption did not have a material impact on the Partnership’s accompanying
interim unaudited condensed financial statements. See Note 5, Derivative Financial
Instruments.
ROCKIES
REGION 2006 LIMITED PARTNERSHIP
NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS
September
30, 2009
(unaudited)
Recently Issued Accounting
Standards
Fair
Value Measurements and Disclosures
In August
2009, the FASB issued changes regarding fair value measurements and disclosures
to reduce potential ambiguity in financial reporting when measuring the fair
value of liabilities. These changes clarify existing guidance that in
circumstances in which a quoted price in an active market for the identical
liability is not available, an entity is required to measure fair value using
either a valuation technique that uses a quoted price of either a similar
liability or a quoted price of an identical or similar liability when traded as
an asset, or another valuation technique that is consistent with the principles
of fair value measurements, such as an income approach (e.g., present value
technique). This guidance also states that both a quoted price in an
active market for the identical liability and a quoted price for the identical
liability when traded as an asset in an active market when no adjustments to the
quoted price of the asset are required are Level 1 fair value
measurements. These changes become effective for the Partnership on
October 1, 2009. The Partnership has not determined the impact, if
any, that these changes will have on the Partnership’s financial
statements.
Consolidation
– Variable Interest Entities
In June
2009, the FASB issued changes surrounding an entity’s analysis to determine
whether any of its variable interests constitute controlling financial interests
in a variable interest entity. This analysis identifies the primary
beneficiary of a variable interest entity as the enterprise that has both of the
following characteristics:
|
·
|
the
power to direct the activities of a variable interest entity that most
significantly impact the entity’s economic performance
and
|
|
·
|
the
obligation to absorb losses of the entity that could potentially be
significant to the variable interest entity or the right to receive
benefits from the entity that could potentially be significant to the
variable interest entity.
|
Additionally,
the entity is required to assess whether it has an implicit financial
responsibility to ensure that a variable interest entity operates as designed
when determining whether it has the power to direct the activities of the
variable interest entity that most significantly impact the entity’s economic
performance. The guidance also requires ongoing reassessments of
whether an enterprise is the primary beneficiary of a variable interest
entity. These changes are effective for the Partnership’s financial
statements issued for fiscal years beginning after November 15, 2009, with
earlier adoption prohibited. The Partnership is evaluating the impact
that the adoption of these changes will have on the Partnership’s financial
statements, related disclosure and management’s discussion and
analysis.
Modernization
of Oil and Gas Reporting
In
January 2009, the SEC published its final rule regarding the modernization of
oil and gas reporting, which modifies the SEC’s reporting and disclosure rules
for oil and natural gas reserves. The most notable changes of the
final rule include the replacement of the single day period-end pricing to value
oil and natural gas reserves to a 12-month average of the first day of the month
price for each month within the reporting period. The final rule also
permits voluntary disclosure of probable and possible reserves, a disclosure
previously prohibited by SEC rules. The revised reporting and
disclosure requirements are effective for the Partnership’s Annual Report on
Form 10-K for the year ending December 31, 2009. Early adoption is
not permitted. The Partnership is evaluating the impact that adoption
of this final rule will have on the Partnership’s financial statements, related
disclosure and management’s discussion and analysis.
ROCKIES
REGION 2006 LIMITED PARTNERSHIP
NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS
September
30, 2009
(unaudited)
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. The fair value of derivative instruments previously reported
at December 31, 2008, in which individual contracts held by each counterparty
were aggregated, or netted, for determining presentation as a net asset, or net
liability of the Partnership, have been reclassified to conform to the current
year individual contract presentation methodology.
Undistributed
oil and natural gas revenues collected by the Managing General Partner from the
Partnership’s customers in the amount of $943,564 and $2,382,497 as of September
30, 2009 and December 31, 2008, respectively, are included in the balance sheet
caption “Due from Managing General Partner - other, net.” This
$2,382,497 portion of undistributed oil and natural gas revenues at December 31,
2008 has been reclassified from “Accounts Receivable” to “Due from Managing
General Partner – other, net” to conform to current year
presentation. Realized gains or losses from derivative transactions
that have not yet been distributed to the Partnership are included in the
balance sheet captions “Due from Managing General Partner-other, net” or “Due to
Managing General Partner-other, net,” respectively. Undistributed
realized gains amounted to $862,932 as of September 30, 2009 and $2,099,787 as
of December 31, 2008, respectively. All other unsettled transactions
between the Partnership and the Managing General Partner are recorded net on the
balance sheet under the caption “Due from (to) Managing General Partner – other,
net.”
The
following table presents transactions with the Managing General Partner and its
affiliates for the periods described below. “Well operations and
maintenance” and “Gathering, compression and processing fees” are included in
“Production and operating costs” on the Statements of
Operations. Additionally, refer to Note 5, Derivative Financial
Instruments for derivative transactions between the Partnership and the
Managing General Partner.
Three months ended
September 30,
|
Nine months ended
September 30,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
Well
operations and maintenance
|
$ | 684,765 | $ | 781,276 | $ | 2,147,570 | $ | 2,473,995 | ||||||||
Gathering,
compression and processing fees
|
54,376 | 75,170 | 157,125 | 228,132 | ||||||||||||
Direct
costs - general and administrative
|
82,344 | 177,233 | 451,902 | 552,978 | ||||||||||||
Cash
distributions*
|
1,607,263 | 2,432,385 | 4,930,587 | 7,598,913 |
*Cash
distributions include $2,510 and $8,166 during the three and nine months ended
September 30, 2009, respectively, and $3,219 and $8,417 during the three and
nine months ended September 30, 2008, respectively, related to equity cash
distributions on Investor Partner units repurchased by PDC. For
additional disclosure regarding the Unit Repurchase Program, refer to Note 1,
General and Basis of
Presentation.
Distributions
to partners in 2009 were impacted by a non-recurring item. The
Partnership’s payment to the Managing General Partner for royalty settlement
costs of $0.2 million decreased distributions during the period. This
amount had been previously accrued by the Partnership in “Due from Managing
General Partner – other, net.” For more information on the Colorado Royalty
Settlement, see Note 6, Commitments and
Contingencies.
ROCKIES
REGION 2006 LIMITED PARTNERSHIP
NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS
September
30, 2009
(unaudited)
Note
4−Fair Value
Measurements
Determination of Fair
Value. The Partnership’s fair value measurements are estimated
pursuant to a fair value hierarchy that requires the Partnership to maximize the
use of observable inputs and minimize the use of unobservable inputs when
measuring fair value. The valuation hierarchy is based upon the
transparency of inputs to the valuation of an asset or liability as of the
measurement date, giving the highest priority to quoted prices in active markets
(Level 1) and the lowest priority to unobservable data (Level 3). In
some cases, the inputs used to measure fair value might fall in different levels
of the fair value hierarchy. The lowest level input that is
significant to a fair value measurement in its entirety determines the
applicable level in the fair value hierarchy. Assessing the
significance of a particular input to the fair value measurement in its entirety
requires judgment, considering factors specific to the asset or liability, and
may affect the valuation of the assets and liabilities and their placement
within the fair value hierarchy levels. The three levels of inputs
that may be used to measure fair value are defined as:
|
·
|
Level 1 –
Quoted prices (unadjusted) in active markets for identical assets or
liabilities. Included in Level 1 are commodity derivative
instruments for New York Mercantile Exchange, or NYMEX, based natural gas
swaps.
|
|
·
|
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. Included in Level 3 are the Partnership’s commodity
derivative instruments for Colorado Interstate Gas, or CIG, based
fixed-price natural gas swaps, collars and floors, oil swaps and natural
gas basis protection swaps.
|
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 future 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 two investment grade financial institutions as counterparties to its
derivative contracts, who hold the majority of the Managing General Partner’s
derivative assets. The Managing General Partner has evaluated the
credit risk of the Partnership’s derivative assets from counterparties holding
its 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, the Partnership has determined that the impact of
counterparty non-performance on the fair value of the Partnership’s derivative
instruments is insignificant. As of September 30, 2009, no adjustment
for credit risk was recorded by the Partnership. Furthermore, while
the Managing General Partner believes these valuation methods are appropriate
and consistent with that 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.
ROCKIES
REGION 2006 LIMITED PARTNERSHIP
NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS
September
30, 2009
(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 for the periods described.
Level 1
|
Level 3
|
Total
|
||||||||||
As
of December 31, 2008
|
||||||||||||
Assets:
|
||||||||||||
Commodity
based derivatives
|
$ | - | $ | 7,782,028 | $ | 7,782,028 | ||||||
Total
assets
|
- | 7,782,028 | 7,782,028 | |||||||||
Liabilities:
|
||||||||||||
Basis
protection derivative contracts
|
- | (300,410 | ) | (300,410 | ) | |||||||
Total
liabilities
|
- | (300,410 | ) | (300,410 | ) | |||||||
Net
asset
|
$ | - | $ | 7,481,618 | $ | 7,481,618 | ||||||
As
of September 30, 2009
|
||||||||||||
Assets:
|
||||||||||||
Commodity
based derivatives
|
$ | 9,919 | $ | 2,898,102 | $ | 2,908,021 | ||||||
Total
assets
|
9,919 | 2,898,102 | 2,908,021 | |||||||||
Liabilities:
|
||||||||||||
Commodity
based derivatives
|
(372,015 | ) | (180,430 | ) | (552,445 | ) | ||||||
Basis
protection derivative contracts
|
- | (3,466,979 | ) | (3,466,979 | ) | |||||||
Total
liabilities
|
(372,015 | ) | (3,647,409 | ) | (4,019,424 | ) | ||||||
Net
liability
|
$ | (362,096 | ) | $ | (749,307 | ) | $ | (1,111,403 | ) |
The
following table sets forth the changes of the Partnership’s Level 3 derivative
financial instruments measured on a recurring basis:
Nine
months ended
|
||||
September 30, 2009
|
||||
Fair
value, net asset, as of December 31, 2008
|
$ | 7,481,618 | ||
Changes
in fair value included in statement of operations line
item:
|
||||
Oil
and gas price risk management loss, net
|
(2,874,423 | ) | ||
Settlements
|
(5,356,502 | ) | ||
Fair
value, net liability, as of September 30, 2009
|
$ | (749,307 | ) | |
Change
in unrealized gains (losses) relating to assets (liabilities) still held
as of September 30, 2009, included in statement of operations line
item:
|
||||
Oil
and gas price risk management, net
|
$ | (3,697,818 | ) |
See Note
5, Derivative Financial
Instruments, for additional disclosure related to the Partnership’s
derivative financial instruments.
Non-Derivative Assets and
Liabilities. The carrying values of the financial instruments
comprising “Cash and cash equivalents,” “Accounts receivable,” “Accounts payable
and accrued expenses” and “Due to (from) Managing General Partner-other, net,”
approximate fair value due to the short-term maturities of these
instruments.
The
Partnership periodically assesses its proved oil and gas properties for possible
impairment, upon a triggering event, by comparing net capitalized costs to
estimated undiscounted future net cash flows on a field-by-field basis using
estimated production based upon estimated prices at which the Partnership
reasonably estimates the commodity to be sold. The estimates of
future prices may differ from current market prices of oil and natural
gas. Certain events, including but not limited to, downward revisions
in estimates to the Partnership’s reserve quantities, expectations of falling
commodity prices or rising operating costs may result in a triggering event and,
therefore, a possible impairment of the Partnership’s oil and natural gas
properties. If, when assessing impairment, net capitalized costs
exceed undiscounted future net cash flows, the measurement of impairment is
based on estimated fair value utilizing a future discounted cash flow analysis
and is measured by the amount by which the net capitalized costs exceed their
fair value. During the nine months ended September 30, 2009 and 2008,
there were no triggering events; therefore no impairment of oil and gas
properties was recognized.
ROCKIES
REGION 2006 LIMITED PARTNERSHIP
NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS
September
30, 2009
(unaudited)
The
Partnership accounts for asset retirement obligations by recording the estimated
fair value of the plugging and abandonment obligations when incurred, at the
time the well is completely drilled. The Partnership estimates the
fair value of the plugging and abandonment obligations based on a discounted
cash flows analysis. Upon initial recognition of an asset retirement
obligation, the Partnership increases the carrying amount of the long-lived
asset by the same amount as the liability. Periodically, the
liabilities are accreted for the change in present value, through charges to
“Accretion of asset retirement obligations” on the statement of
operations. The initial capitalized costs are depleted based on the
useful lives of the related assets, through charges to depreciation, depletion
and amortization, or DD&A. If the fair value of the estimated
asset retirement obligation changes, an adjustment is recorded to both the asset
retirement obligation and the asset retirement cost. Revisions in
estimated liabilities can result from revisions of estimated inflation rates,
escalating retirement costs and changes in the estimated timing of settling
asset retirement obligations.
Note
5−Derivative Financial
Instruments
The
Partnership is exposed to the effect of market fluctuations in the prices of oil
and natural gas. Price risk represents the potential risk of loss
from adverse changes in the market price of oil and natural gas
commodities. The Managing General Partner employs established
policies and procedures to manage the risks associated with these market
fluctuations using derivative instruments. Partnership policy
prohibits the use of oil and natural gas derivative instruments for speculative
purposes.
The
Partnership recognizes all derivative instruments as either assets or
liabilities on the accompanying interim unaudited condensed balance sheets at
fair value. The Partnership has elected not to designate any of the
Partnership’s derivative instruments as hedges. Accordingly, changes
in the fair value of those derivative instruments allocated to the Partnership
are recorded in the Partnership’s statements of operations. Changes
in the fair value of derivative instruments related to the Partnership’s oil and
gas sales activities are recorded in “Oil and gas price risk management,
net.”
Valuation
of a contract’s fair value is performed internally. While the Managing General
Partner uses common industry practices to develop the Partnership’s valuation
techniques, changes in pricing methodologies or the underlying assumptions could
result in different fair values. See Note 4, Fair Value Measurements, for
a discussion of how the Managing General Partner determines the fair value of
the Partnership’s derivative instruments.
As of
September 30, 2009, the Managing General Partner had derivative contracts in
place for a portion of the Partnership’s anticipated production through 2012 for
a total of 2,074 MMbtu of natural gas and 77 MBbls of crude
oil. During late October 2009, the Managing General Partner entered
into additional NYMEX fixed-price gas swaps ($6.67 to $7.11) and NYMEX gas
collars ($6.00-$6.10 floor: $8.27-$8.60 ceiling) covering all monthly periods
from November 2010 to December 2013. The Partnership will be allocated positions
by the Managing General Partner for MMbtu’s equal to the number of remaining
MMbtu’s of basis protection swaps at September 30, 2009 which were not
previously covered by NYMEX fixed-price gas swaps or gas collars.
Derivative
Strategies. The Partnership’s results of operations and
operating cash flows are affected by changes in market prices for oil and
natural gas. To mitigate a portion of the exposure to adverse market
changes, the Managing General Partner has entered into various derivative
contracts.
For
Partnership oil and gas sales, the Managing General Partner enters into, for a
portion of the Partnership’s production, derivative contracts to protect against
price declines in future periods. While these derivatives are structured to
reduce exposure to changes in price associated with the derivative commodity,
they also limit the benefit the Partnership might otherwise have received from
price increases in the physical market. The Partnership believes the
derivative instruments in place continue to be effective in achieving the risk
management objectives for which they were intended.
ROCKIES
REGION 2006 LIMITED PARTNERSHIP
NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS
September
30, 2009
(unaudited)
As of
September 30, 2009, the Partnership’s oil and natural gas derivative instruments
were comprised of commodity collars, commodity swaps and basis protection
swaps.
|
·
|
Collars
contain a fixed floor price (put) and ceiling price (call). If
the market price falls below the fixed put strike price, PDC, as Managing
General Partner, receives the market price from the purchaser and receives
the difference between the put strike price and market price from the
counterparty. If the market price exceeds the fixed call strike
price, PDC, as Managing General Partner, receives the market price from
the purchaser and pays the difference between the call strike price and
market price to the counterparty. If the market price is
between the call and put strike price, no payments are due to or from the
counterparty.
|
|
·
|
Swaps
are arrangements that guarantee a fixed price. If the market
price is below the fixed contract price, PDC, as Managing General Partner,
receives the market price from the purchaser and receives the difference
between the market price and the fixed contract price from the
counterparty. If the market price is above the fixed contract
price, PDC, as Managing General Partner, receives the market price from
the purchaser and pays the difference between the market price and the
fixed contract price to the
counterparty.
|
|
·
|
Basis
protection swaps are arrangements that guarantee a price differential for
natural gas from a specified delivery point. For CIG basis
protection swaps, which traditionally have negative differentials to
NYMEX, PDC, as Managing General Partner, receives a payment from the
counterparty if the price differential is greater than the stated terms of
the contract and pays the counterparty if the price differential is less
than the stated terms of the
contract.
|
ROCKIES
REGION 2006 LIMITED PARTNERSHIP
NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS
September
30, 2009
(unaudited)
The
following table summarizes the location and fair value amounts of the
Partnership’s derivative instruments in the accompanying balance sheets as of
September 30, 2009, and December 31, 2008.
Fair Value
|
||||||||||||
Balance
Sheet
|
September 30,
|
December 31,
|
||||||||||
Derivative instruments not designated as
hedge (1):
|
Line Item
|
2009
|
2008
|
|||||||||
Derivative
Assets:
|
Current
|
|||||||||||
Commodity
contracts
|
Due
from Managing General Partner-derivatives
|
$ | 2,713,191 | $ | 5,772,399 | |||||||
Non Current
|
||||||||||||
Commodity
contracts
|
Due
from Managing General Partner-derivatives
|
194,830 | 2,009,629 | |||||||||
Total
Derivative Assets
|
$ | 2,908,021 | $ | 7,782,028 | ||||||||
Derivative
Liabilities:
|
Current
|
|||||||||||
Commodity
contracts
|
Due
to Managing General Partner-derivatives
|
$ | (332,231 | ) | $ | - | ||||||
Basis
protection contracts
|
Due
to Managing General Partner-derivatives
|
(703,681 | ) | - | ||||||||
Non Current
|
||||||||||||
Commodity
contracts
|
Due
to Managing General Partner-derivatives
|
(220,214 | ) | - | ||||||||
Basis
protection contracts
|
Due
to Managing General Partner-derivatives
|
(2,763,298 | ) | (300,410 | ) | |||||||
Total
Derivative Liabilities
|
$ | (4,019,424 | ) | $ | (300,410 | ) | ||||||
(1)
As of September 30, 2009 and December 31, 2008, none of the Partnership’s
derivative instruments were designated
hedges.
|
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, 2009 and 2008.
Three months ended September
30,
|
||||||||||||||||||||||||
2009
|
2008
|
|||||||||||||||||||||||
Statement
of operations line item
|
Reclassification of Realized Gains (Losses)
Included in Prior Periods Unrealized
|
Realized and Unrealized Gains (Losses) 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
|
||||||||||||||||||
Oil
and gas price risk management, net
|
||||||||||||||||||||||||
Realized
gains (losses)
|
$ | 1,328,325 | $ | (2,953 | ) | $ | 1,325,372 | $ | (1,544,429 | ) | $ | 1,938,756 | $ | 394,327 | ||||||||||
Unrealized
(losses) gains
|
(1,328,325 | ) | (1,308,968 | ) | (2,637,293 | ) | 1,544,429 | 9,097,358 | 10,641,787 | |||||||||||||||
Total
oil and gas price risk management (loss) gain, net
|
$ | - | $ | (1,311,921 | ) | $ | (1,311,921 | ) | $ | - | $ | 11,036,114 | $ | 11,036,114 |
Nine months ended September
30,
|
||||||||||||||||||||||||
2009
|
2008
|
|||||||||||||||||||||||
Statement
of operations line item
|
Reclassification of Realized Gains (Losses)
Included in Prior Periods Unrealized
|
Realized and Unrealized Gains (Losses) 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
|
||||||||||||||||||
Oil
and gas price risk management, net
|
||||||||||||||||||||||||
Realized
gains (losses)
|
$ | 4,352,668 | $ | 1,003,834 | $ | 5,356,502 | $ | (886,298 | ) | $ | (633,296 | ) | $ | (1,519,594 | ) | |||||||||
Unrealized
(losses) gains
|
(4,352,668 | ) | (4,240,353 | ) | (8,593,021 | ) | 886,298 | 2,809,057 | 3,695,355 | |||||||||||||||
Total
oil and gas price risk management (loss) gain, net
|
$ | - | $ | (3,236,519 | ) | $ | (3,236,519 | ) | $ | - | $ | 2,175,761 | $ | 2,175,761 |
Concentration of Credit Risk.
A significant portion of the Partnership’s liquidity is concentrated in
derivative instruments that enables the Partnership to manage a portion of its
exposure to price volatility from producing oil and natural
gas. These arrangements expose the Partnership to credit risk of
nonperformance by the counterparties. The Managing General Partner
primarily uses two financial institutions, who are also major lenders in the
Managing General Partner’s credit facility agreement, as counterparties to the
derivative contracts.
ROCKIES
REGION 2006 LIMITED PARTNERSHIP
NOTES TO
UNAUDITED CONDENSED FINANCIAL STATEMENTS
September
30, 2009
(unaudited)
Note
6−Commitments and
Contingencies
Colorado Royalty
Settlement. On May 29, 2007, Glen Droegemueller, individually
and as representative plaintiff on behalf of all others similarly situated,
filed a class action complaint against the Managing General Partner in the
District Court, Weld County, Colorado alleging that the Managing General Partner
underpaid royalties on natural gas produced from wells operated by the Managing
General Partner in parts of the State of Colorado (the “Droegemueller
Action”). The plaintiff sought declaratory relief and to recover an
unspecified amount of compensation for underpayment of royalties paid by the
Managing General Partner pursuant to leases. The Managing General
Partner moved the case to Federal Court on June 28, 2007. On October
10, 2008, the court preliminarily approved a settlement agreement between the
plaintiffs and the Managing General Partner, on behalf of itself and the
Partnership. Although the Partnership was not named as a party in the
suit, the lawsuit states that this action relates to all wells operated by the
Managing General Partner, which includes a majority of the Partnership’s 64
wells in the Wattenberg field. The portion of the settlement relating
to the Partnership’s wells for all periods through September 30, 2009 that has
been expensed by the Partnership is approximately $195,000 including associated
legal costs of approximately $16,000. This entire settlement of
$178,788 was deposited by the Managing General Partner into an escrow account on
November 3, 2008. Notice of the settlement was mailed to members of
the class action suit in the fourth quarter of 2008. The final
settlement was approved by the court on April 7, 2009. Settlement
distribution checks were mailed in July 2009. During September 2009,
all settlement costs were passed through to the Partners and related required
judicial action from the settlement of the suit was implemented in this
distribution.
Colorado Stormwater
Permit. On December 8, 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, 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 oil and gas
companies operating in the Piceance region of Colorado. Operating
expenses, including amounts arising from this notice, if any, are allocated
among the eight users of the road based upon their respective
usage. The Partnership has 23 wells in this region. The
Notice alleges a deficient and/or incomplete stormwater management plan, failure
to implement best management 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. No civil penalties have been
imposed or requested at this time. Given the preliminary stage of
this proceeding and the inherent uncertainty in administrative actions of this
nature, the Managing General Partner is unable to predict the ultimate outcome
of this administrative action at this time and therefore no amounts have been
recorded on the Partnership’s financial records.
Derivative
Contracts. The Partnership is exposed to oil and natural gas
price fluctuations on underlying sales contracts should the counterparties to
the Managing General Partner’s derivative instruments not
perform. The Managing General Partner has had no counterparty default
losses and expects full performance by the counterparties to these agreements in
the future.
Note
7−Subsequent
Events
The
Partnership evaluated the Partnership’s activities subsequent to September 30,
2009, through November 13, 2009 (the date the financial statements were issued),
and have concluded that no subsequent events have occurred that would require
recognition in the Partnership’s financial statements or disclosure in the notes
to the unaudited condensed financial statements.
ROCKIES
REGION 2006 LIMITED PARTNERSHIP
(A
West Virginia Limited Partnership)
Item
2.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
|
Special
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’s” or the “Registrant’s”) 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 oil and natural gas production and reserves,
drilling plans, future cash flows, anticipated liquidity, anticipated capital
expenditures and the Managing General Partner Petroleum Development
Corporation’s (“MGP’s” or “PDC’s”) strategies, plans and
objectives. However, these 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 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 oil and
natural gas;
|
|
·
|
risks
incident to the operation of natural gas and oil
wells;
|
|
·
|
future
production and development costs;
|
|
·
|
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;
|
|
·
|
the
effect of natural gas and oil derivatives
activities;
|
|
·
|
conditions
in the capital markets; and
|
|
·
|
losses
possible from pending or future
litigation.
|
Further,
the Partnership urges you to carefully review and consider the cautionary
statements made in this report, the Partnership’s annual report on Form 10-K for
the year ended December 31, 2008 filed with the Securities and Exchange
Commission (“SEC”) on March 31, 2009 (“2008 Form 10-K”), 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 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.
Overview
Rockies
Region 2006 Limited Partnership engages in the development, production and sale
of oil and natural gas. The Partnership began oil and gas operations
in September 2006 and currently operates 91 gross (90.4 net) wells located in
the Rocky Mountain Region in the states of Colorado and 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, on behalf of the Partnership through the D&O
Agreement, may 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.
ROCKIES
REGION 2006 LIMITED PARTNERSHIP
(A
West Virginia Limited Partnership)
Results of
Operations
The
following table sets forth selected information regarding the Partnership’s
results of operations, including production volumes, oil and natural gas sales,
average sales prices received, average sales price including realized derivative
gains and losses, production and operating costs, depreciation, depletion and
amortization costs, other operating income and expenses for the three and nine
months ended September 30, 2009, or the current three and nine month periods,
and the three and nine months ended September 30, 2008, or the prior three and
nine month periods.
Summary of Operating
Results
|
||||||||||||||||||||||||
Three months ended
September 30,
|
Nine months ended
September 30,
|
|||||||||||||||||||||||
2009
|
2008
|
Change
|
2009
|
2008
|
Change
|
|||||||||||||||||||
Number
of producing wells (end of period)
|
91 | 90 | * | 91 | 90 | * | ||||||||||||||||||
Production: (1)
|
||||||||||||||||||||||||
Oil
(Bbl)
|
24,299 | 34,600 | -30 | % | 82,702 | 118,320 | -30 | % | ||||||||||||||||
Natural
gas (Mcf)
|
466,899 | 612,774 | -24 | % | 1,426,910 | 1,961,560 | -27 | % | ||||||||||||||||
Natural
gas equivalents (Mcfe) (2)
|
612,693 | 820,374 | -25 | % | 1,923,122 | 2,671,480 | -28 | % | ||||||||||||||||
Average
Selling Price (excluding realized gain (loss) on
derivatives)
|
||||||||||||||||||||||||
Oil
(per Bbl)
|
$ | 60.73 | $ | 102.04 | -40 | % | $ | 48.51 | $ | 98.47 | -51 | % | ||||||||||||
Natural
gas (per Mcf)
|
2.63 | 7.11 | -63 | % | 2.60 | 7.56 | -66 | % | ||||||||||||||||
Natural
gas equivalents (per Mcfe)
|
4.41 | 9.62 | -54 | % | 4.01 | 9.91 | -60 | % | ||||||||||||||||
Realized
Gain (Loss) on Derivatives, net
|
||||||||||||||||||||||||
Oil
derivatives - realized gain (loss)
|
$ | 308,397 | $ | (327,999 | ) | 194 | % | $ | 1,376,044 | $ | (962,470 | ) | -243 | % | ||||||||||
Natural
gas derivatives - realized gain (loss)
|
1,016,975 | 722,326 | -41 | % | 3,980,458 | (557,124 | ) | * | ||||||||||||||||
Total
realized gain (loss) on derivatives, net
|
$ | 1,325,372 | $ | 394,327 | -236 | % | $ | 5,356,502 | $ | (1,519,594 | ) | * | ||||||||||||
Average
Selling Price (including realized gain (loss) on
derivatives)
|
||||||||||||||||||||||||
Oil
(per Bbl)
|
$ | 73.42 | $ | 92.56 | -21 | % | $ | 65.15 | $ | 90.33 | -28 | % | ||||||||||||
Natural
gas (per Mcf)
|
4.81 | 8.29 | -42 | % | 5.39 | 7.28 | -26 | % | ||||||||||||||||
Natural
gas equivalents (per Mcfe)
|
6.58 | 10.10 | -35 | % | 6.80 | 9.35 | -27 | % | ||||||||||||||||
Average
cost per Mcfe
|
||||||||||||||||||||||||
Production
and operating costs (3)
|
$ | 1.47 | $ | 1.75 | -16 | % | $ | 1.42 | $ | 1.74 | -18 | % | ||||||||||||
Depreciation,
depletion and amortization
|
3.62 | 3.12 | 16 | % | 3.70 | 3.12 | 19 | % | ||||||||||||||||
Revenues:
|
||||||||||||||||||||||||
Oil
and natural gas sales
|
$ | 2,703,900 | $ | 7,890,247 | -66 | % | $ | 7,718,377 | $ | 26,486,935 | -71 | % | ||||||||||||
Realized
gain (loss) on derivatives, net
|
1,325,372 | 394,327 | 236 | % | 5,356,502 | (1,519,594 | ) | * | ||||||||||||||||
Unrealized
(loss) gain on derivatives, net
|
(2,637,293 | ) | 10,641,787 | -125 | % | (8,593,021 | ) | 3,695,355 | * | |||||||||||||||
Total
revenues
|
$ | 1,391,979 | $ | 18,926,361 | -93 | % | $ | 4,481,858 | $ | 28,662,696 | -84 | % | ||||||||||||
Operating
costs and expenses:
|
||||||||||||||||||||||||
Production
and operating costs
|
$ | 902,587 | $ | 1,433,870 | -37 | % | $ | 2,740,184 | $ | 4,656,025 | -41 | % | ||||||||||||
Direct
costs - general and administrative
|
82,344 | 177,233 | -54 | % | 451,902 | 552,978 | -18 | % | ||||||||||||||||
Depreciation,
depletion and amortization
|
2,220,461 | 2,560,044 | -13 | % | 7,115,045 | 8,327,128 | -15 | % | ||||||||||||||||
Exploratory
dry hole costs
|
37,162 | 35,737 | 4 | % | 37,243 | 84,268 | -56 | % | ||||||||||||||||
Accretion
of asset retirement obligations
|
10,139 | 9,635 | 5 | % | 30,417 | 28,727 | 6 | % | ||||||||||||||||
Total
operating costs and expenses
|
$ | 3,252,693 | $ | 4,216,519 | -23 | % | $ | 10,374,791 | $ | 13,649,126 | -24 | % | ||||||||||||
(Loss)
income from operations
|
$ | (1,860,714 | ) | $ | 14,709,842 | -113 | % | $ | (5,892,933 | ) | $ | 15,013,570 | -139 | % | ||||||||||
Gain
on sale of leasehold
|
- | - | * | - | 120,000 | -100 | % | |||||||||||||||||
Interest
expense
|
(5,892 | ) | - | * | (5,892 | ) | - | * | ||||||||||||||||
Interest
income
|
- | 13,162 | -100 | % | 7,418 | 73,033 | -90 | % | ||||||||||||||||
Net
(loss) income
|
$ | (1,866,606 | ) | $ | 14,723,004 | -113 | % | $ | (5,891,407 | ) | $ | 15,206,603 | -139 | % | ||||||||||
Cash
distributions
|
$ | 4,337,169 | $ | 6,565,316 | -34 | % | $ | 13,303,848 | $ | 20,425,483 | -35 | % |
*Percentage
change not meaningful, equal to or greater than 250% or not
calculable. Amounts may not calculate due to rounding.
_______________
|
(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.
|
ROCKIES
REGION 2006 LIMITED PARTNERSHIP
(A
West Virginia Limited Partnership)
|
(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)
|
Production
costs represent oil and gas 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 prices rebounded somewhat from earlier in 2009, through September
2009. The Partnership continued to experience the depressed natural
gas prices from the significant declines in late July 2008 through the end of
2008. While the Partnership’s production decreased to 1,923 MMcfe for
the 2009 nine-month period compared to 2,672 MMcfe for the same 2008 period, a
decrease of 28%, the Partnership’s average sales price declined $5.90 per Mcfe,
a decrease of 60%. While the significant changes in commodity prices
have impacted the Partnership’s results of operations, the Managing General
Partner believes that it was successful in managing the Partnership’s operations
to reduce the negative impacts of lower prices through the Partnership’s
derivative positions. The Partnership’s realized derivative gains for
the 2009 nine month period of $5.4 million added an average of $2.79 per Mcfe
produced during the 2009 nine month period. At September 30, 2009,
the Managing General Partner estimates the net fair value of the Partnership’s
open derivative positions to be a net liability of $1.1 million.
There
were two primary contributors to the $5.4 million decrease in oil and gas price
risk management, net. A decrease in future prices at September 30,
2009 compared to December 30, 2008 resulted in a $12.3 million increase in
unrealized derivative losses. This was partially offset by a $6.9
million increase in realized derivative gains which resulted from depressed
commodity prices for the 2009 nine month period, as compared to the higher
prices in the same 2008 period. Unrealized gains and losses are
non-cash items and these non-cash charges to the Partnership’s statement of
operations will continue to fluctuate with the fluctuation in commodity prices
until the positions mature or are closed, at which time they will become
realized or cash items. The Partnership has elected not to designate
any of the Partnership’s derivative instruments as hedges. Under
hedge accounting, changes in the fair value of derivatives less amounts
reclassified to realized gains/losses are shown as other comprehensive income in
the statement of equity and not in the statement of operations. While
the required accounting treatment of recording all changes in the fair value of
derivatives in the statement of operations, for derivatives that are not
designated as hedges, may result in significant swings in operating results over
the life of the derivatives, the combination of the settled derivative contracts
and the revenue received from the oil and gas sales at delivery are expected to
result in a more predictable cash flow stream than would the sales contracts
without the associated derivatives.
The table
below, which demonstrates the markets’ expected volatility in commodity pricing,
sets forth the average NYMEX and CIG prices for the next 24 months (forward
curve) from the selected dates:
September 30,
|
March 31,
|
September 30,
|
October 31,
|
|||||||||||||||
Commodity
|
Index
|
2008
|
2009
|
2009
|
2009
|
|||||||||||||
Natural
gas: (per
MMbtu)
|
||||||||||||||||||
NYMEX
|
$ | 8.21 | $ | 5.44 | $ | 6.25 | $ | 6.00 | ||||||||||
CIG
|
5.46 | 4.15 | 5.64 | 5.49 | ||||||||||||||
Oil:
(per
Bbl)
|
NYMEX
|
103.63 | 59.35 | 74.64 | 81.26 |
ROCKIES
REGION 2006 LIMITED PARTNERSHIP
(A
West Virginia Limited Partnership)
Oil and Natural Gas
Sales
Partnership
production decreased to 613 MMcfe and 1,923 MMcfe for the current year three and
nine month periods, respectively, from 820 MMcfe and 2,672 MMcfe for the prior
year three and nine month periods, respectively. The Partnership’s
oil and gas sales revenue, excluding price risk management impact, for the
current three and nine month periods decreased from comparable periods by $5.2
million and $18.8 million, respectively, due to a significant decline in
commodity prices and decreased volumes. For the current three and
nine month periods, approximately $3.2 million and $11.4 million, respectively,
of the decrease in oil and natural gas sales revenue, was due to pricing, and
$2.0 million and $7.4 million, respectively, was due to decreased
production
The
Partnership expects to experience continued declines in both oil and natural gas
production volumes over the wells’ life cycles until such time that the
Partnership’s Wattenberg wells may be successfully
recompleted. Subsequent to a successful recompletion, production will
once again begin to decline.
Oil and Natural Gas
Pricing
Financial
results depend upon many factors, particularly the price of oil and natural gas
and the Partnership’s ability to market its production
effectively. Oil and natural gas prices are among the most volatile
of all commodity prices. These price variations have a material
impact on the Partnership’s financial results. Oil and natural gas
prices also vary by region and locality, depending upon the distance to markets,
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 have resulted in a local market oversupply situation 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 and
transportation capacity beyond the Partnership’s control.
The price
the Partnership receives for the natural gas produced in the Rocky Mountain
Region is based on a variety of prices, which primarily includes natural gas
sold at CIG prices with a portion sold at Mid-Continent, San Juan Basin,
Southern California or other nearby region prices. The CIG Index, and
other indices for production delivered to other Rocky Mountain pipelines, has
historically been less than the price received for natural gas produced in the
eastern regions, which is NYMEX based. This negative differential has
narrowed in recent months and has even more recently become a positive
differential. CIG was $1.79 lower than NYMEX in January 2009,
narrowed to close at $0.37 lower in October 2009 and has more recently closed at
$0.02 higher than NYMEX for November 2009.
Oil and Gas Price Risk
Management, Net
The
Managing General Partner uses oil and natural gas derivative instruments to
manage price risk for PDC as well as sponsored drilling
partnerships. The Managing General Partner sets these instruments for
PDC, and the various partnerships managed by PDC. Prior to September
30, 2008, as volumes produced changed, the mix between PDC and the partnerships
changed on a pro-rata basis. As of September 30, 2008, PDC has fixed
the allocation of the derivative positions between PDC and each
partnership. Existing positions are allocated based on fixed
quantities for each position and new positions will have specific designations
relative to the applicable partnership.
ROCKIES
REGION 2006 LIMITED PARTNERSHIP
(A
West Virginia Limited Partnership)
The
following table presents the primary composition of “Oil and gas price risk
management, net” for the periods described:
Three months ended
September 30,
|
Nine months ended
September 30,
|
|||||||||||||||
Oil
and gas price risk management, net
|
2009
|
2008
|
2009
|
2008
|
||||||||||||
Realized
gains (losses)
|
||||||||||||||||
Oil
|
$ | 308,397 | $ | (327,999 | ) | $ | 1,376,044 | $ | (962,470 | ) | ||||||
Natural
Gas
|
1,016,975 | 722,326 | 3,980,458 | (557,124 | ) | |||||||||||
Total
realized gain (loss), net
|
1,325,372 | 394,327 | 5,356,502 | (1,519,594 | ) | |||||||||||
Unrealized
gains (losses)
|
||||||||||||||||
Reclassification
of realized (gains) losses included in prior periods
unrealized
|
(1,328,325 | ) | 1,544,429 | (4,352,668 | ) | 886,298 | ||||||||||
Unrealized
(loss) gain for the period
|
(1,308,968 | ) | 9,097,358 | (4,240,353 | ) | 2,809,057 | ||||||||||
Total
unrealized (loss) gain, net
|
(2,637,293 | ) | 10,641,787 | (8,593,021 | ) | 3,695,355 | ||||||||||
Oil
and gas price risk management (loss) gain, net
|
$ | (1,311,921 | ) | $ | 11,036,114 | $ | (3,236,519 | ) | $ | 2,175,761 |
Realized
gains recognized in the current year three and nine month periods, are a result
of lower oil and gas commodity prices at settlement date compared to the
respective contract price. During the current year three month
period, the Partnership recorded unrealized derivative losses on the
Partnership’s CIG basis swaps of $0.8 million, as the forward basis differential
between NYMEX and CIG has continued to narrow and unrealized losses on the
Partnership’s collars of $ 0.3 million and natural gas swaps of $0.2 million as
pricing curves have rebounded slightly from prior periods. During the
current year nine month period, the Partnership recorded unrealized derivative
losses on its oil swaps of $0.7 million, as the forward strip price of oil
rebounded during the quarter, and on the Partnership’s CIG basis swaps of $3.2
million, for the same reason cited above. The Partnership also
recorded unrealized losses on the Partnership’s natural gas swaps of $0.3
million as natural gas prices, which had declined in previous quarters, have
risen slightly above those price levels reflected in previous forward
curves.
Oil and
gas price risk management, net includes realized gains and losses and unrealized
changes in the fair value of derivative instruments related to the Partnership’s
oil and natural gas production. See Note 4, Fair Value Measurements, and
Note 5, Derivative Financial
Instruments, to the accompanying unaudited condensed financial statements
for additional details of the Partnership’s derivative financial
instruments.
Oil and Natural Gas Sales Derivative
Instruments. The Managing General Partner uses various
derivative instruments to manage fluctuations in oil and natural gas
prices. The Partnership has in place a series of collars, fixed-price
swaps and basis protection swaps on a portion of the Partnership’s oil and
natural gas production as set forth in the following table.
ROCKIES
REGION 2006 LIMITED PARTNERSHIP
(A
West Virginia Limited Partnership)
This
table identifies the Partnership’s derivative positions related to oil and gas
sales activities in effect as of September 30, 2009, on the Partnership’s
production. The Partnership’s production volumes for the three months
ended September 30, 2009 were 24,299 Bbls of oil and 466,899 Mcf of natural
gas.
Collars
|
Fixed-Price Swaps
|
Basis Protection Swaps
|
||||||||||||||||||||||||||||||||||
Floors
|
Ceilings
|
|||||||||||||||||||||||||||||||||||
Commodity/
Operating Area/
Index
|
Quantity
(Gas-MMbtu
Oil-Bbls)
|
Weighted
Average
Contract Price
|
Quantity
(Gas-MMbtu
Oil-Bbls)
|
Weighted
Average
Contract Price
|
Quantity
(Gas-MMbtu
Oil-Bbls)
|
Weighted
Average
Contract Price
|
Quantity
(Gas-MMbtu
Oil-Bbls)
|
Weighted
Average
Contract Price
|
Fair Value At
September 30,
2009(1)
|
|||||||||||||||||||||||||||
Natural
Gas
|
||||||||||||||||||||||||||||||||||||
Rocky
Mountain Region
|
||||||||||||||||||||||||||||||||||||
CIG
|
||||||||||||||||||||||||||||||||||||
4Q
2009
|
241,572 | $ | 6.64 | 241,572 | $ | 8.18 | 86,574 | $ | 9.20 | - | $ | - | $ | 969,138 | ||||||||||||||||||||||
2010
|
264,430 | 6.67 | 264,430 | 8.09 | 129,861 | 9.20 | 754,971 | 1.88 | (105,708 | ) | ||||||||||||||||||||||||||
2011
|
119,103 | 4.75 | 119,103 | 9.45 | - | - | 842,171 | 1.88 | (929,169 | ) | ||||||||||||||||||||||||||
2012
|
- | - | - | - | - | - | 850,608 | 1.88 | (878,192 | ) | ||||||||||||||||||||||||||
2013
|
- | - | - | - | - | - | 763,069 | 1.88 | (731,593 | ) | ||||||||||||||||||||||||||
NYMEX
|
||||||||||||||||||||||||||||||||||||
2010
|
30,275 | 5.75 | 30,275 | 8.30 | 705,607 | 5.61 | - | - | (373,705 | ) | ||||||||||||||||||||||||||
2011
|
40,636 | 5.75 | 40,636 | 8.30 | 228,460 | 6.96 | - | - | 5,890 | |||||||||||||||||||||||||||
2012
|
- | - | - | - | 227,807 | 6.96 | - | - | (10,398 | ) | ||||||||||||||||||||||||||
Total
Natural Gas
|
(2,053,737 | ) | ||||||||||||||||||||||||||||||||||
Oil
|
||||||||||||||||||||||||||||||||||||
Rocky
Mountain Region
|
||||||||||||||||||||||||||||||||||||
NYMEX
|
||||||||||||||||||||||||||||||||||||
4Q
2009
|
- | - | - | - | 13,874 | 90.52 | - | - | 269,577 | |||||||||||||||||||||||||||
2010
|
- | - | - | - | 43,380 | 92.96 | - | - | 799,257 | |||||||||||||||||||||||||||
2011
|
- | - | - | - | 19,554 | 70.75 | - | - | (126,500 | ) | ||||||||||||||||||||||||||
Total
Oil
|
942,334 | |||||||||||||||||||||||||||||||||||
Total
Natural Gas and Oil
|
$ | (1,111,403 | ) |
(1)
Approximately 67% of the total fair value of the derivative instruments was
measured using significant unobserved inputs (Level 3 assets and liabilities).
See Note 4, Fair Value
Measurements, to the accompanying interim unaudited condensed financial
statements.
During
late October 2009, the Managing General Partner entered into additional NYMEX
fixed-price gas swaps ($6.67 to $7.11) and NYMEX gas collars ($6.00-$6.10 floor:
$8.27-$8.60 ceiling) covering all monthly periods from November 2010 to December
2013. The Partnership will be allocated positions by the Managing General
Partner for MMbtu’s equal to the number of remaining MMbtu’s of basis protection
swaps at September 30, 2009 which were not previously covered by NYMEX
fixed-price gas swaps or gas collars.
Production and Operating
Costs
Generally,
production and operating costs vary either with total oil and natural gas sales
or production volumes. Property and severance taxes are estimated by
the Managing General Partner based on rates determined using historical
information. These amounts are subject to revision based on actual
amounts determined during future filings by the Managing General Partner with
the taxing authorities. Property and severance taxes vary directly
with total oil and natural gas 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. General oil field services and all other costs vary and can
fluctuate based on services required. These costs include water
hauling and disposal, equipment repairs and maintenance, snow removal and
service rig workovers.
For the
nine months ended September 30, 2009 compared to the same period in 2008, oil
and natural gas production, on an energy equivalency-basis, decreased 28%, due
to reduced production resulting from the Wattenberg Field high pipeline pressure
during the first half of 2009 and normally-occurring production declines
throughout an oil and natural gas well’s production life
cycle. Production and operating costs were lower by $1.9 million, or
41%, due to volume-associated reductions of $1.3 million in production taxes,
natural gas transport and lease operating expenses. In addition
to volume-associated production tax decreases, lower commodity valuations
further reduced production taxes by approximately $0.9 million which was
slightly offset by higher lease operating expenses of $0.2 million due to the
changing production mix from the larger Grand Valley Field to the smaller
Wattenberg Field. Production and operating costs per Mcfe were $1.42
for the nine months ended September 30 of 2009 compared to $1.74 for the
comparable period in 2008.
ROCKIES
REGION 2006 LIMITED PARTNERSHIP
(A
West Virginia Limited Partnership)
For the
three months ended September 30, 2009, compared to the same period in 2008, oil
and natural gas production declined 25% which reduced volume-associated
expenditures by $0.3 million. Additionally, a decrease of $0.3
million in production-related taxes, due to lower commodity valuations, which
was slightly offset by higher lease operating expenses of approximately $60,000,
combined to lower overall production and operating costs by approximately $0.5
million. Production and operating costs per Mcfe were $1.47 and $1.75
for the three month period ended September 30, 2009 and 2008,
respectively.
Direct Costs−General and
Administrative
Direct
costs – general and administrative consist primarily of professional fees for
financial statement audits, income tax return preparation and legal
matters. Direct costs declined during the nine months ended September
30, 2009, compared to the same period in 2008, by $0.1 million, due to a
reduction of direct administration costs and an approximately $57,000 reduction
of Colorado Royalty Settlement costs which were recognized as a liability during
the third quarter 2008, upon the litigation’s initial court-approved settlement
in October 2008. Direct costs – general and administrative also
declined during the three months ended September 30, 2009, compared to the same
period in 2008, by $0.1 million, also due primarily to the liability recognition
of periods prior to third quarter 2008, of costs associated to the Colorado
Royalty Settlement. For more information on the Colorado Royalty Settlement, see
Note 6, Commitments and
Contingencies.
Depreciation, Depletion and
Amortization
Depreciation,
depletion and amortization (DD&A) expense results solely from the
depreciation, depletion and amortization of well equipment and lease
costs. The calculation of DD&A expense is directly related to
reserves and production volumes. DD&A expense is primarily based
upon year-end proved developed producing oil and gas reserves. These
reserves are priced at the price of oil and natural gas as of December 31 each
year. If prices increase, the estimated volume of oil and gas
reserves may increase, resulting in decreases in the rate of DD&A expense
per unit of production. If prices decrease, as they did from December
31, 2007 to December 31, 2008, the estimated volumes of oil and gas reserves may
decrease resulting in increases in the rate of DD&A expense per unit of
production.
The
DD&A rate per Mcfe increased to $3.62 and $3.70 for the three and nine month
periods ended September 30, 2009, respectively, compared to $3.12 for both
periods ended September 30, 2008. These increased rates, offset by
lower production volumes, resulted in decreases of $0.3 million and $1.2 million
in DD&A for the three and nine months ended September 30, 2009 compared to
same periods in 2008, respectively. This is primarily the result of
production level decreases of 25% and 28%, respectively, for each of the three
and nine month periods ended September 30, 2009, partially offset by an increase
in per Mcfe expense due to lower proved developed reserves at December 31, 2008
compared to December 31, 2007. While both production and overall
year-end reserves are expected to decline gradually year-to-year over the wells’
remaining life cycles, downward revisions to proved developed oil and natural
gas reserves in the annual 2008 reserve report resulted in the increased
DD&A unit cost increases during the three and nine month periods ended
September 30, 2009 as compared to the same periods in 2008.
Exploratory Dry Hole
Costs
The
Partnership incurred approximately $37,000 in plugging and abandonment costs for
a Partnership Nesson Formation, North Dakota dry hole during the three months
ended September 30, 2009, which resulted in the Partnership’s exploratory dry
hole costs remaining substantially unchanged for the three month period ended
September 30, 2009. The Partnership’s approximately $37,000 in
exploratory dry hole costs for the nine month period ended September 30, 2009,
declined from the $0.1 million in exploratory dry hole costs incurred during the
comparable period in 2008.
ROCKIES
REGION 2006 LIMITED PARTNERSHIP
(A
West Virginia Limited Partnership)
Interest
Expense
The
Partnership incurred interest expense of approximately $5,900 for the three and
nine months ended September 30, 2009, related to amounts funded by the Managing
General Partner in November 2008, into escrow on behalf of the Partnership,
which were subsequently paid to Colorado Royalty Settlement litigants in July
2009. Interest rates paid by the Partnership were determined in
accordance with the Applicable Federal Interest Rate applicable to Qualified
Legal Settlements under Internal Revenue Code §468B. For more
information on the Colorado Royalty Settlement, see Note 6, Commitments and
Contingencies, to the accompanying unaudited condensed financial
statements and Note 2, Summary
of Significant Accounting Policies, Due from (to) Managing General Partner –
other, net, to the 2008 Form 10-K.
Interest
Income
Significantly
lower undistributed revenues held by the Managing General Partner, and
significantly lower interest rates applied to those undistributed amounts,
resulted in no interest income during the three month period and lower interest
income, during the nine month period ended September 30, 2009, respectively,
compared to the same periods in 2008.
Liquidity and Capital
Resources
Oil and
gas production from the Partnership’s existing properties declined rapidly in
the first two years (mid 2007 through mid 2009) and is expected to continue to
decline gradually over the remaining lives of the wells. Therefore
the Partnership may be unable to maintain its current level of oil and gas
production and cash flows from operations if commodity prices remain in their
current depressed state for a prolonged period beyond 2009. This
decreased production would have a material negative impact on the Partnership’s
operations and may result in reduced cash distributions to the Investor Partners
in 2010 and beyond.
Working
Capital
Working
capital at September 30, 2009 was $1.7 million compared to working capital of
$9.3 million at December 31, 2008. This decrease of $7.6 million was
due to a decrease in receivables from oil and gas sales at September 30, 2009 to
$7.6 million as compared to $3.5 million at December 31, 2008. In
addition, the receivables at September 30, 2009 for realized and short-term net
unrealized derivative gains which decreased $0.9 million and $1.7 million,
respectively, from the amounts at December 31, 2008 of $2.3 million and $5.8
million, respectively. In September 2009, there was a decrease in Due from
Managing General Partner – other, net, of $0.2 million due to the Partnership’s
settlement of the obligation for the Colorado Royalty Settlement of $0.2 million
with the Managing General Partner. For more information on the
Colorado Royalty Settlement see Note 6, Commitments and Contingencies
to the accompanying interim unaudited condensed financial
statements. The cash impact of this transaction decreased
distributions by $0.2 million during the quarter.
Cash
Flows From Investing Activities
In 2009,
the Partnership received an approximately $50,000 refund from the State of
Colorado for state sales taxes charged during 2007 on well tubing and casing
purchases during the Partnership’s drilling operations, which were subsequently
determined to be tax-exempt. The Partnership has from time-to-time,
invested in additional equipment which supports treatment, delivery and
measurement of oil & gas or environmental protection. These amounts, which
included the installation of a Wattenberg Field compressor unit which improved
production deliverability, totaled approximately $174,000 for the nine months
ended September 30, 2009.
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 $60.2 million through September 30, 2009. The table
below sets forth the cash distributions to the Managing General Partner and
Investor Partners including Managing General Partner distribution relating to
limited partnership units repurchased for the periods described as
follows:
Three months ended September
30,
|
||||||||||||||||||||||
2009
|
2008
|
|||||||||||||||||||||
Managing General Partner
Distributions
|
Investor Partners
Distributions
|
Total Distributions
|
Managing General Partner
Distributions
|
Investor Partners
Distributions
|
Total Distributions
|
|||||||||||||||||
$ | 1,604,753 | $ | 2,732,416 | $ | 4,337,169 | $ | 2,429,166 | $ | 4,136,150 | $ | 6,565,316 |
Nine months ended September
30,
|
||||||||||||||||||||||
2009
|
2008
|
|||||||||||||||||||||
Managing General Partner
Distributions
|
Investor Partners
Distributions
|
Total Distributions
|
Managing General Partner
Distributions
|
Investor Partners
Distributions
|
Total Distributions
|
|||||||||||||||||
$ | 4,922,421 | $ | 8,381,427 | $ | 13,303,848 | $ | 7,590,496 | $ | 12,834,987 | $ | 20,425,483 |
Investor
Partner cash distributions include $2,510 and $8,166 during the three and nine
months ended September 30, 2009, respectively, and $3,219 and $8,417 during the
three and nine months ended September 30, 2008, respectively, related to equity
cash distributions on Investor Partner units repurchased by the Managing General
Partner.
Cash
Flows From Operating Activities
The
Partnership’s operations are expected to be conducted with available funds and
revenues generated from its oil and natural gas production
activities. Changes in cash flow from operations are largely due to
the same factors that affect the Partnership’s net income that are more fully
discussed under Results of
Operations, excluding the non-cash items depreciation, depletion and
amortization and unrealized gains and losses on derivative
transactions. Based on current oil and natural gas prices and prices
set by derivatives, and the Partnership’s anticipated production, the
Partnership expects positive cash flows from operations for the remainder of
2009.
Changes
in market prices for oil and natural gas, the Partnership’s production levels,
the impact of realized gains and losses on the Partnership’s oil and natural gas
derivative instruments and changes in costs are the principal determinants of
the level of the Partnership cash flow from operations. Oil and
natural gas sales for the nine months ended September 30, 2009 were
approximately 71% lower than the same period in the prior year, resulting from a
60% decrease in average oil and natural gas prices and a 28% decrease in oil and
natural gas production. While a decline in oil and natural gas prices
would affect the amount of cash from operations that would be generated, the
Partnership has oil and natural gas derivative positions in place, as of the
date of this filing, covering 56% of the Partnership’s expected oil production
and 70% of its expected natural gas production for the remainder of 2009, at
average prices of $90.52 per Bbl and $7.32 per Mcf,
respectively. These contracts reduce the impact of price changes on
cash provided by operations for a substantial portion of the expected production
for the remainder of 2009. However, the remaining 44% and 30% of
estimated remaining 2009 oil and natural gas production, respectively, is not
subject to the Partnership’s derivative instrument risk management;
consequently, associated revenues will be directly impacted by changing
commodity market prices.
The
Partnership’s current derivatives positions could change based on changes in oil
and natural gas futures markets, the investors’ view of underlying oil and
natural gas supply and demand trends and changes in volumes
produced. Partnership oil and natural gas derivatives as of September
30, 2009 are detailed in Note 5, Derivative Financial
Instruments to the accompanying interim unaudited condensed financial
statements.
ROCKIES
REGION 2006 LIMITED PARTNERSHIP
(A
West Virginia Limited Partnership)
Net cash
provided by operating activities was $13.2 million for the nine months ended
September 30, 2009 compared to $20.5 million during the same period in 2008, a
decrease of $7.3 million or 36%. Variances between the two
periods in cash provided by operating activities were due primarily to the
following:
|
·
|
A
decrease in oil and gas sale revenues of $18.8 million, or 71%,
accompanied by increases in direct costs – general and administrative of
$0.1 million; and
|
|
·
|
An
increase in realized oil and gas price risk management, net of $6.9
million and a decrease in production and operating cost of $1.9 million or
18%.
|
|
·
|
A
decrease in Due from Managing General Partner – other, net, of $0.2
million in September 2009, due to the Partnership’s $0.2 million payment
to the Managing General Partner for royalty settlement
costs. For more information on the Colorado Royalty Settlement
see Note 6, Commitments
and Contingencies to the accompanying interim unaudited condensed
financial statements.
|
Information
related to the oil and gas reserves of the Partnership’s wells is discussed in
detail in the Partnership’s Annual Report on Form 10-K Supplemental Oil and Gas
Information−Unaudited, Net
Proved Oil and Gas Reserves and Information and Standardized Measure of Discounted
Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas
Reserves.
No bank
borrowings are anticipated until such time as recompletions of the Codell
formation in the Wattenberg Field wells are undertaken by the Partnership that
is expected to occur based on a favorable general economic environment
and commodity price structure. Partnership well recompletions, which
provide for additional reserve development and production, generally occur five
to seven years after initial well drilling so that well resources are optimally
utilized. There are
no immediate plans to initiate recompletion activities in the Wattenberg Field
wells owned by the Partnership. As the optimal period approaches, the
Managing General Partner will re-evaluate the feasibility of commencing those
recompletions based on engineering data and a favorable commodity price
environment in order to maximize the financial benefit of the
recompletion. However, no assurances can be given that recompletion
activities will be feasible or economic.
Commitments and
Contingencies
See Note
6, Commitments and
Contingencies to the accompanying unaudited condensed financial
statements.
Recent Accounting
Standards
See Note
2, Recent Accounting
Standards to the accompanying unaudited condensed financial statements,
included in this report for recent accounting standards.
Critical Accounting Policies
and Estimates
The
preparation of the accompanying unaudited condensed financial statements in
conformity with accounting principles generally accepted in the United States of
America 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.
The
Partnership believes that the Partnership’s accounting policies for revenue
recognition, derivatives instruments, fair value measurements, oil and natural
gas properties and asset retirement obligations are based on, among other
things, judgments and assumptions made by management that include inherent risks
and uncertainties. There have been no significant changes to these
policies 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 Form 10-K for the year
ended December 31, 2008. Certain amounts reported at December 31,
2008, more fully detailed in Note 3, −Transactions with Managing General
Partner and Affiliates to the accompanying financial statements have been
reclassified on the Partnership’s balance sheet to conform to the current year
classifications with no effect on previously reported net income or Partners’
equity. Reclassifications include amounts related to undistributed
oil and gas revenues and the fair value of unexpired derivative
instruments.
ROCKIES
REGION 2006 LIMITED PARTNERSHIP
(A
West Virginia Limited Partnership)
Item 3.
|
Quantitative
and Qualitative Disclosures About Market
Risk
|
Not
Applicable
Item
4T.
|
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.
2008 Material
Weakness
As
discussed in the Management’s
Report on Internal Control Over Financial Reporting included in the
Partnership’s 2008 Annual Report on Form 10-K, the Partnership did not maintain
effective internal controls over financial reporting as of December 31, 2008,
over transactions that are directly related to and processed by the Partnership,
in that the Partnership failed to maintain sufficient documentation to
adequately assess the operating effectiveness of internal control over financial
reporting. More specifically, the Partnership’s financial close and
reporting narrative failed to adequately describe the process, identify key
controls and assess segregation of duties. This material weakness has
not been remediated as of September 30, 2009. The 2008 Annual Report
on Form 10-K did not include an attestation report of the Partnership’s
independent registered public accounting firm regarding internal control over
financial reporting pursuant to Item 308T (a)(4) of Regulation
S-K. Pursuant to Final Order dated October 19, 2009, temporary Item
308T was extended through December 15, 2010. Accordingly, the
Partnership will file the attestation report of the Partnership’s independent
registered public accounting firm regarding internal control with the
Partnership’s Annual Report on Form 10-K as of December 31, 2010.
(a) Evaluation of Disclosure
Controls and Procedures
As of
September 30, 2009, 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 its Chief
Executive Officer and 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 the Partnership files or
submits under the Exchange Act is recorded, processed, summarized and reported,
within the time periods specified in the SEC’s rules and forms, and that such
information is accumulated and communicated to the Partnership’s management,
including its principal executive and principal financial officers as
appropriate to allow timely decisions regarding required
disclosure.
Based
upon that evaluation, the Managing General Partner’s Chief Executive Officer and
Chief Financial Officer concluded that the Partnership’s disclosure controls and
procedures were not effective as of September 30, 2009 due to the existence of
the material weakness described above in 2008 Material Weakness
included in this Item 4 (T). Because of the nature of the material
weakness noted, the Partnership is not able to quantify the dollar amounts of
exposure or potential range of the dollar amount of potential revisions to the
financial statements, from this material weakness.
(b) Remediation of Material
Weakness in Internal Control
PDC, the
Managing General Partner, with participation from the Audit Committee of its
Board of Directors, has been addressing the material weakness disclosed in the
Partnership’s 2008 Annual Report on Form 10-K. The Managing General
Partner believes that with effective implementation of planned changes in
internal controls over financial reporting outlined below, that it will be able
to remediate this known material weakness as of December 31,
2009. However, this control weakness will not be considered
remediated until the changes in internal controls over financial reporting are
operating effectively for a sufficient period of time and the Managing General
Partner has concluded, through testing, that these controls are operating
effectively.
ROCKIES
REGION 2006 LIMITED PARTNERSHIP
(A
West Virginia Limited Partnership)
The
Partnership made the following changes in its internal control over financial
reporting (such as defined in Rules 13a-15(f) and 15d-15(f) of the Securities
Exchange Act of 1934) during the quarter ended September 30, 2009.
The
Partnership developed documentation that materially describes the business
processes and identifies key controls for internal control over financial
reporting that will assist the Managing General Partner in adequately assessing
the control over financial reporting for the Partnership. In
addition, the Partnership developed documentation to adequately assess
segregation of duties. At present, the Partnership has not quantified
the total cost of this initiative; however the majority of this cost is expected
to be paid by the Managing General Partner.
Until
PDC, the Managing General Partner, is able to conclude that the Partnership has
remediated this known material weakness in internal control over financial
reporting, the Managing General Partner will continue to perform additional
analysis and procedures in order to ensure that the Partnership’s financial
statements contained in its subsequent SEC filings are prepared in accordance
with generally accepted accounting principles in the United States.
(c) Other Changes in Internal
Control over Financial Reporting
During
the 2009 third quarter, PDC made the following changes in PDC’s internal control
over financial reporting (as such defined in Rules 13a-15(f) and 15d-15(f) of
the Securities Exchange Act of 1934) that have materially affected or are
reasonably likely to materially affect the Partnership’s internal control over
financial reporting:
|
·
|
Effective
July 1, 2009, as part of PDC’s broader financial reporting system, PDC
implemented a new partnership investor distribution accounting module to
the existing accounting software. PDC has taken the necessary
steps to monitor and maintain appropriate internal controls during this
period of change. These steps included procedures to preserve
the integrity of the data converted and a review by the business owners to
validate data converted. Additionally, PDC provided training
related to the business process changes and the financial reporting system
software to individuals using the financial reporting system to carry out
their job responsibilities, as well as, those who rely on the financial
information. PDC anticipates that the implementation of this
module will strengthen the overall systems of internal controls due to
enhanced automation and integration of related processes. PDC
is modifying the design and documentation of internal control process and
procedures relating to the new module to supplement and complement
existing internal control over financial reporting. The system
changes were undertaken to integrate systems and consolidate information
and were not undertaken in response to any actual or perceived
deficiencies in PDC’s internal control over financial
reporting. Testing of the controls related to these new systems
is ongoing and is included in the scope of PDC’s assessment of its
internal control over financial reporting for
2009.
|
The
Managing General Partner continues to evaluate the ongoing effectiveness and
sustainability of the changes PDC made in internal control over financial
reporting, and, as a result of the ongoing evaluation, may identify additional
changes to improve internal control over financial reporting. Further
information regarding the material weakness of the Partnership referenced above
may be found in the Partnership’s Annual Report on 10-K for the year ended
December 31, 2008 under Item 9A (T), Controls and Procedures −
Management’s Report on
Internal Control Over Financial Reporting.
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 in 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.
Other
Repurchases: Individual investor partners periodically offer
and PDC repurchases, units on a negotiated basis before the third anniversary of
the date of the first cash distribution. There were no repurchases
during the three month period ended September 30, 2009.
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 PDC, the Managing
General Partner of the Partnership
|
10-12G/A
Amend 1
|
000-52787
|
10.2
|
12/24/2007
|
|||||||
Rule
13a-14(a)/15d-14(c) Certification of Chief Executive Officer of Petroleum
Development Corporation, the Managing General Partner of the Partnership
as adopted pursuant to Section of the Sarbanes-Oxley Act of
2002.
|
X
|
|||||||||||
Rule
13a-14(a)/15d-14(c) Certification of Chief Financial Officer of Petroleum
Development Corporation, the Managing General Partner of the Partnership
as adopted pursuant to Section of the Sarbanes-Oxley Act of
2002.
|
X
|
|||||||||||
Title
18 U.S.C. Section 1350 (Section 906 of Sarbanes-Oxley Act of 2002)
Certifications by Chief Executive Officer and Chief Financial Officer of
Petroleum Development Corporation, the Managing General Partner of the
Partnership.
|
X
|
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
By: /s/ Richard W.
McCullough
|
||
Richard
W. McCullough
Chairman
and Chief Executive Officer
November
13, 2009
|
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
13, 2009
|
|
Richard
W. McCullough
|
Petroleum
Development Corporation
|
||
Managing
General Partner of the Registrant
|
|||
(Principal
executive officer)
|
|||
/s/ Gysle R. Shellum
|
Chief
Financial Officer
|
November
13, 2009
|
|
Gysle
R. Shellum
|
Petroleum
Development Corporation
|
||
Managing
General Partner of the Registrant
|
|||
(Principal
financial officer)
|
|||
/s/ R. Scott Meyers
|
Chief
Accounting Officer
|
November
13, 2009
|
|
R.
Scott Meyers
|
Petroleum
Development Corporation
|
||
Managing
General Partner of the Registrant
|
|||
(Principal
accounting officer)
|
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