PDC 2002 B LTD PARTNERSHIP - FORM 10-Q - August 14, 2013

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EX-31.1 - 302 CERTIFICATION OF CHIEF EXECUTIVE OFFICER - PDC 2002 B LTD PARTNERSHIPa2002b-ex311_20130630.htm
EX-32.1 - 906 CERTIFICATION OF CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER - PDC 2002 B LTD PARTNERSHIPa2002b-ex321_20130630.htm
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EX-31.2 - 302 CERTIFICATION OF CHIEF FINANCIAL OFFICER - PDC 2002 B LTD PARTNERSHIPa2002b-ex312_20130630.htm

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2013
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 000-50227

PDC 2002-B Limited Partnership

(Exact name of registrant as specified in its charter)
 
West Virginia
 
38-3648762
 
 
(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)

Registrant's telephone number, including area code: (303) 860-5800

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.
Yes R No £

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
 
Large accelerated filer  £
 
Accelerated filer  £
 
 
 
 
 
 
 
Non-accelerated filer £
 
Smaller reporting company R
 
 
(Do not check if a smaller reporting company)
 
 

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

As of June 30, 2013 this Partnership had 559.02 units of limited partnership interest and no units of additional general partnership interest outstanding.


PDC 2002-B Limited Partnership


TABLE OF CONTENTS





SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (“Securities Act”) and Section 21E of the Securities Exchange Act of 1934 ("Exchange Act") regarding this Partnership's business, financial condition and results of operations. PDC Energy, Inc. (“PDC”) is the Managing General Partner of this Partnership. All statements other than statements of historical facts included in and incorporated by reference into this report are “forward-looking statements” within the meaning of the safe harbor provisions of the United States ("U.S.") Private Securities Litigation Reform Act of 1995. Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein. These statements relate to, among other things: estimated crude oil, natural gas and natural gas liquids ("NGLs") reserves; future production, expenses, cash flows and liquidity; anticipated capital expenditures and projects; availability of additional midstream facilities and services in the Wattenberg Field and timing and benefits of that availability; the effectiveness of the Managing General Partner's derivative program in providing a degree of price stability; and the Managing General Partner's future strategies, plans and objectives.
The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect the Managing General Partner's good faith judgment, such statements can only be based on facts and factors currently known to the Managing General Partner. Consequently, forward-looking statements are inherently subject to risks and uncertainties, including known and unknown risks and uncertainties incidental to the development, production and marketing of crude oil, natural gas and NGLs, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements.
Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:
•
changes in production volumes and worldwide demand, including economic conditions that might impact demand;
•
volatility of commodity prices for crude oil, natural gas and NGLs;
•
the impact of governmental policies and/or regulations, including changes in environmental and other laws, the interpretation and enforcement related to those laws and regulations, liabilities arising thereunder and the costs to comply with those laws and regulations;
•
potential declines in the value of this Partnership's crude oil and natural gas properties resulting in impairments;
•
changes in estimates of proved reserves;
•
inaccuracy of reserve estimates and expected production rates;
•
potential for production decline rates from this Partnership's wells to be greater than expected;
•
availability of future cash flows for investor distributions or funding of development activities;
•
timing and extent of this Partnership's success in further developing and producing this Partnership's reserves;
•
the Managing General Partner's ability to acquire supplies and services at reasonable prices;
•
timing and receipt of necessary regulatory permits;
•
risks incidental to the additional development and operation of crude oil and natural gas wells;
•
this Partnership's future cash flows, liquidity and financial condition;
•
competition in the oil and gas industry;
•
availability of sufficient pipeline, gathering and other transportation facilities and related infrastructure to process and transport this Partnership's production, particularly in the Wattenberg Field, and the impact of these facilities on the price this Partnership receives for its production;
•
success of the Managing General Partner in marketing this Partnership's crude oil, natural gas and NGLs;
•
impact of environmental events, governmental and other third-party responses to such events and the Managing General Partner's ability to insure adequately against such events;
•
cost of pending or future litigation;
•
adjustments relating to asset dispositions that may be unfavorable to this Partnership;
•
the Managing General Partner's ability to retain or attract senior management and key technical employees; and
•
success of strategic plans, expectations and objectives for future operations of the Managing General Partner.
Further, this Partnership urges the reader to carefully review and consider the cautionary statements and disclosures made in this Quarterly Report on Form 10-Q, this Partnership's Annual Report on Form 10-K for the year ended December 31, 2012(“2012 Form 10-K”) filed with the U.S. Securities and Exchange Commission (“SEC”) on March 15, 2013 and this Partnership's other filings with the SEC for further information on risks and uncertainties that could affect this Partnership's business, financial condition, results of operations and cash flows. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date of this report. This Partnership undertakes no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. All forward looking statements are qualified in their entirety by this cautionary statement.

- 1-

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

PDC 2002-B Limited Partnership
Condensed Balance Sheets
(unaudited)

 
June 30, 2013
 
December 31, 2012
Assets
 
 
 

Current assets:
 
 
 

Cash and cash equivalents
$
445,394

 
$
10,137

Accounts receivable
33,775

 
21,527

Crude oil inventory
8,791

 
24,499

Due from Managing General Partner-derivatives
—

 
180,165

Total current assets
487,960

 
236,328

 
 
 
 
Crude oil and natural gas properties, successful efforts method, at cost
2,213,790

 
3,167,657

Less: Accumulated depreciation, depletion and amortization
(1,608,131
)
 
(2,270,162
)
Crude oil and natural gas properties, net
605,659

 
897,495

Other assets
52,217

 
49,653

 
 
 
 
Total Assets
$
1,145,836

 
$
1,183,476

 
 
 
 
Liabilities and Partners' Equity
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued expenses
$
23,660

 
$
2,522

Due to Managing General Partner-derivatives
—

 
81,917

Due to Managing General Partner-other, net
28,988

 
67,520

Total current liabilities
52,648

 
151,959

Asset retirement obligations
163,781

 
223,265

Total liabilities
216,429

 
375,224

 
 
 
 
Commitments and contingent liabilities


 


 
 
 
 
Partners' equity:
 
 
 
   Managing General Partner
257,351

 
232,462

   Limited Partners - 559.02 units issued and outstanding
672,056

 
575,790

Total Partners' equity
929,407

 
808,252

Total Liabilities and Partners' Equity
$
1,145,836

 
$
1,183,476

    






See accompanying notes to unaudited condensed financial statements.

- 2-

PDC 2002-B Limited Partnership
Condensed Statements of Operations
(unaudited)

 
Three months ended June 30,
 
Six months ended June 30,
 
2013
 
2012
 
2013
 
2012
Revenues:
 
 
 
 
 
 
 
Crude oil, natural gas and NGLs
$
37,512

 
$
62,442

 
$
93,755

 
$
138,086

Commodity price risk management gain (loss), net
6,175

 
(16,833
)
 
(13,770
)
 
44,291

Total revenues
43,687

 
45,609

 
79,985

 
182,377

Operating costs and expenses:
 
 
 
 
 
 
 
Crude oil, natural gas and NGLs production costs
22,544

 
19,576

 
52,646

 
41,647

Direct costs - general and administrative
32,625

 
31,038

 
63,311

 
59,896

Depreciation, depletion and amortization
12,760

 
38,400

 
30,334

 
87,121

Accretion of asset retirement obligations
2,826

 
2,626

 
5,601

 
5,204

Total operating costs and expenses
70,755

 
91,640

 
151,892

 
193,868

 
 
 
 
 
 
 
 
Loss from operations
(27,068
)
 
(46,031
)
 
(71,907
)
 
(11,491
)
 
 
 
 
 
 
 
 
Interest income
22

 
5

 
27

 
10

Loss from continuing operations
(27,046
)
 
(46,026
)
 
$
(71,880
)
 
$
(11,481
)
 
 
 
 
 
 
 
 
Income (loss) from discontinued operations
202,275

 
17,152

 
208,590

 
(59,355
)
 
 
 
 
 
 
 
 
Net income (loss)
$
175,229

 
$
(28,874
)
 
$
136,710

 
$
(70,836
)
 
 
 
 
 
 
 
 
Loss from continuing operations
$
(27,046
)
 
$
(46,026
)
 
$
(71,880
)
 
$
(11,481
)
Less: Managing General Partner interest in loss from continuing operations
(5,409
)
 
(9,205
)
 
(14,376
)
 
(2,296
)
Loss from continuing operations allocated to Investor Partners
$
(21,637
)
 
$
(36,821
)
 
$
(57,504
)
 
$
(9,185
)
 
 
 
 
 
 
 
 
Income (loss) from discontinued operations
$
202,275

 
$
17,152

 
$
208,590

 
$
(59,355
)
Less: Managing General Partner interest in income (loss) from discontinued operations
40,455

 
3,430

 
41,718

 
(11,871
)
Income (loss) from discontinued operations allocated to Investor Partners
$
161,820

 
$
13,722

 
$
166,872

 
$
(47,484
)
 
 
 
 
 
 
 
 
Net income (loss) per Investor Partner unit
 
 
 
 
 
 
 
Continuing operations
$
(39
)
 
$
(66
)
 
$
(103
)
 
$
(16
)
Discontinued operations
290

 
25

 
299

 
(85
)
Net income (loss) per Investor Partner unit
$
251

 
$
(41
)
 
$
196

 
$
(101
)
 
 
 
 
 
 
 
 
Investor Partner units outstanding
559.02

 
559.02

 
559.02

 
559.02



See accompanying notes to unaudited condensed financial statements.

- 3-

PDC 2002-B Limited Partnership
Condensed Statements of Cash Flows
(unaudited)

 
Six months ended June 30,
 
2013
 
2012
Cash flows from operating activities:
 
 
 
Net income (loss)
$
136,710

 
$
(70,836
)
Adjustments to net income (loss) to reconcile to net cash from operating activities:
 
 
 
Depreciation, depletion and amortization
36,690

 
108,712

Accretion of asset retirement obligations
7,271

 
7,094

Change in unrealized loss on derivative transactions
72,483

 
33,712

Gain on sale of crude oil and natural gas properties
(201,633
)
 
—

Changes in assets and liabilities:
 
 
 
Accounts receivable
(12,248
)
 
(5,668
)
Crude oil inventory
10,629

 
(8,617
)
Other assets
(2,564
)
 
(3,835
)
Accounts payable and accrued expenses
58

 
(178
)
Due to Managing General Partner-other, net
(31,875
)
 
(39,624
)
Net cash from operating activities
15,521

 
20,760

Cash flows from investing activities:
 
 
 
Capital expenditures for crude oil and natural gas properties
—

 
(2,957
)
Proceeds from sale of crude oil and natural gas properties
435,291

 
—

Net cash from investing activities
435,291

 
(2,957
)
Cash flows from financing activities:
 
 
 
Distributions to Partners
(15,555
)
 
(17,865
)
Net cash from financing activities
(15,555
)
 
(17,865
)
 
 
 
 
Net change in cash and cash equivalents
435,257

 
(62
)
Cash and cash equivalents, beginning of period
10,137

 
10,261

Cash and cash equivalents, end of period
$
445,394

 
$
10,199

 
 
 
 
Supplemental disclosure of non-cash activity:
 
 
 
Change in accounts payable and accrued expenses related
to disposition of properties and equipment
$
(21,079
)
 
$
—

Change in due from managing general partner-other,net
related to disposition of properties and equipment
6,657

 
—








See accompanying notes to unaudited condensed financial statements.

- 4-
PDC 2002-B LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
June 30, 2013
(unaudited)


Note 1 - General and Basis of Presentation

PDC 2002-B Limited Partnership (“Partnership” or the “Registrant”) was organized in 2002 as a limited partnership, in accordance with the laws of the State of West Virginia, for the purpose of engaging in the exploration and development of crude oil and natural gas properties. Business operations commenced upon closing of an offering for the sale of Partnership units. Upon funding, this Partnership entered into a Drilling and Operating Agreement (“D&O Agreement”) with the Managing General Partner which authorizes PDC Energy, Inc. (“PDC”) to conduct and manage this Partnership's business. In accordance with the terms of the Limited Partnership Agreement (the “Agreement”), the Managing General Partner is authorized to manage all activities of this Partnership and initiates and completes substantially all Partnership transactions.

As of June 30, 2013, there were 495 limited partners in this Partnership (the “Investor Partners”). PDC is the designated Managing General Partner of this Partnership and owns a 20% Managing General Partner ownership in this Partnership. According to the terms of the Agreement, revenues, costs and cash distributions of this Partnership are allocated 80% to the Investor Partners, which are shared pro rata based upon the number of units in this Partnership, and 20% to the Managing General Partner. The Managing General Partner may repurchase Investor Partner units under certain circumstances provided by the Agreement, upon request of an individual Investor Partner. Through June 30, 2013, the Managing General Partner had repurchased 42.4 units of Partnership interest from the Investor Partners at an average price of $3,496 per unit. As of June 30, 2013, the Managing General Partner owned 26.1% of this Partnership.

Beginning in November 2009, when the Investor Partners' average annual rate of return fell below 12.8%, this Partnership modified the standard ownership-based pro-rata allocation of Partnership cash available for distribution, pursuant to the Performance Standard Obligation outlined in Section 4.02 of the Agreement. Distributions paid to the Managing General Partner were reduced and distributions to the Investor Partners were increased by $668 and $1,771 for the six months ended June 30, 2013 and 2012, respectively, as a result of the Preferred Cash Distribution made under the terms in Section 4.02. The Managing General Partner's obligation under Section 4.02 expired in February 2013. For more information concerning the Performance Standard Obligation, see Note 8, Partners' Equity and Cash Distributions, to this Partnership's financial statements included in the 2012 Form 10-K.

In the Managing General Partner's opinion, the accompanying unaudited condensed financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary for a fair presentation of this Partnership's results for interim periods in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") and with the instructions to Form 10-Q and Article 8 of Regulation S-X of the SEC. Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in the audited financial statements have been condensed or omitted. The information presented in this Quarterly Report on Form 10-Q should be read in conjunction with this Partnership's audited financial statements and notes thereto included in this Partnership's 2012 Form 10-K. This Partnership's accounting policies are described in the Notes to Financial Statements in this Partnership's 2012 Form 10-K and updated, as necessary, in this Quarterly Report on Form 10-Q. The results of operations and cash flows for the three and six months ended June 30, 2013 are not necessarily indicative of the results to be expected for the full year or any other future period.

Certain reclassifications have been made to prior period financial statements to conform to the current year presentation. The reclassifications are mainly attributable to reporting as discontinued operations the results of operations related to the sale of this Partnership's Piceance Basin assets. See Note 8, Divestitures and Discontinued Operations, for additional information regarding the divestiture. The reclassifications had no impact on previously reported cash flows, net income or Partners’ equity.



- 5-
PDC 2002-B LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
June 30, 2013
(unaudited)

Note 2 - Summary of Significant Accounting Policies

Recently Adopted Accounting Standard

On January 1, 2013, this Partnership adopted changes issued by the Financial Accounting Standards Board regarding the disclosure of offsetting assets and liabilities. These changes require an entity to disclose both gross and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an enforceable master netting arrangement or similar agreement. The enhanced disclosures enable users of an entity’s financial statements to understand and evaluate the effect or potential effect of master netting arrangements on an entity’s financial position, including the effect or potential effect of rights of setoff associated with certain financial instruments and derivative instruments. This Partnership's adoption of these changes had no impact on the unaudited condensed financial statements.

Note 3 - Transactions with Managing General Partner

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

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

    
 
June 30, 2013
 
December 31, 2012
Crude oil, natural gas and NGLs sales revenues
collected from this Partnership's third-party customers
$
24,247

 
$
20,841

Commodity price risk management, realized gain
11,884

 
14,367

Other (1)
(65,119
)
 
(102,728
)
Total Due to Managing General Partner-other, net
$
(28,988
)
 
$
(67,520
)

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

The following table presents Partnership transactions, excluding derivative transactions which are more fully detailed in Note 5, Derivative Financial Instruments, with the Managing General Partner for the three and six months ended June 30, 2013 and 2012. “Well operations and maintenance” and “Gathering, compression and processing fees” are included in the “Crude oil, natural gas and NGLs production costs” line item on the condensed statements of operations for continuing operations or in Note 8, Divestitures and Discontinued Operations, for discontinued operations.    
 
 Three months ended June 30,
 
Six months ended June 30,
 
2013
 
2012
 
2013
 
2012
 Well operations and maintenance
$
42,242

 
$
26,709

 
$
89,765

 
$
130,388

 Gathering, compression and processing fees
2,991

 
6,099

 
6,475

 
10,670

 Direct costs - general and administrative
46,399

 
31,038

 
77,085

 
59,896

 Cash distributions (1) (2)
2,409

 
1,315

 
3,426

 
2,766


(1)
Cash distributions include $483 and $973 during the three and six months ended June 30, 2013, respectively, and $463 and $964 during the three and six months ended June 30, 2012, respectively, related to equity cash distributions for Investor Partner units repurchased by PDC.

- 6-
PDC 2002-B LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
June 30, 2013
(unaudited)

(2)
Cash distributions to the Managing General Partner were reduced by $668 during the six months ended June 30, 2013, and $842 and $1,771 for the three and six months ended June 30, 2012, respectively, due to Preferred Cash Distributions made by the Managing General Partner to Investor Partners under the Performance Standard Obligation provision of the Agreement. For more information concerning this obligation, see Note 1, General and Basis of Presentation.



Note 4 - Fair Value of Financial Instruments

Determination of fair value. This Partnership's fair value measurements are estimated pursuant to a fair value hierarchy that requires this Partnership to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. In these cases, the lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as:

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

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

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

The Managing General Partner measures the fair value of this Partnership's derivative instruments based on a pricing model that utilizes market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, natural gas forward curve, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of the Managing General Partner's credit standing on the fair value of derivative liabilities and the effect of the Managing General Partner's counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position.

The Managing General Partner validates its fair value measurement through the review of counterparty statements and other supporting documentation, the determination that the source of the inputs is valid, the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and assumptions. While the Managing General Partner uses common industry practices to develop its valuation techniques, changes in the Managing General Partner's pricing methodologies or the underlying assumptions could result in significantly different fair values. While the Managing General Partner believes its valuation method is appropriate and consistent with those used by other market participants, the use of a different methodology or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value.

 

- 7-
PDC 2002-B LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
June 30, 2013
(unaudited)

This Partnership's fixed-price swaps and basis swaps as of December 31, 2012 were included in Level 2. The following table presents this Partnership's derivative assets and liabilities that had been measured at fair value on a recurring basis:
 
Balance Sheet
 
 
 
Line Item
 
 Level 2
 
 
 
 
Assets:
 
 
 
Current
 
 
 
Commodity-based derivatives
Due from Managing General Partner-derivatives
 
$
180,165

 Total assets
 
 
180,165

 
 
 
 
Liabilities:
 
 
 
Current
 
 
 
Basis protection derivative contracts
Due to Managing General Partner-derivatives
 
81,917

 Total liabilities
 
 
81,917

 Net asset
 
 
$
98,248

Derivative instruments that were due to mature subsequent to June 30, 2013 were liquidated during the quarter ended June 30, 2013. Accordingly, as of June 30, 2013, this Partnership did not have any derivative instruments in place for its future production.
    
Non-Derivative Financial Assets and Liabilities

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



- 8-
PDC 2002-B LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
June 30, 2013
(unaudited)

Note 5 - Derivative Financial Instruments

The following tables present the impact of this Partnership's derivative instruments on this Partnership's accompanying condensed statements of operations:
 
 
 Three months ended June 30,
 
 
2013
 
2012
Statement of operations line item:
 
Reclassification of Realized Gains (Losses) included in Prior Periods Unrealized
 
Realized Gains for the Current Period
 
Total
 
Reclassification of Realized Gains (Losses) included in Prior Periods Unrealized
 
Realized and Unrealized Losses for the Current Period
 
Total
Commodity price risk management gain (loss), net
 
 
 
 
 
 
 
 
 
 
 
 
Realized gains (losses)
 
$
26,388

 
$
6,175

 
$
32,563

 
$
44,293

 
$
(678
)
 
$
43,615

Unrealized losses
 
(26,388
)
 
—

 
(26,388
)
 
(44,293
)
 
(16,155
)
 
(60,448
)
Total
$
—

 
$
6,175

 
$
6,175

 
$
—

 
$
(16,833
)
 
$
(16,833
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Six months ended June 30,
 
 
2013
 
2012
Statement of operations line item:
 
Reclassification of Realized Gains (Losses) included in Prior Periods Unrealized
 
Realized Losses for the Current Period
 
Total
 
Reclassification of Realized Gains (Losses) included in Prior Periods Unrealized
 
Realized and Unrealized Gains for the Current Period
 
Total
Commodity price risk management gain (loss), net
 
 
 
 
 
 
 
 
 
 
 
 
Realized gains (losses)
 
$
72,483

 
$
(13,770
)
 
$
58,713

 
$
61,477

 
$
16,526

 
$
78,003

Unrealized gains (losses)
 
(72,483
)
 
—

 
(72,483
)
 
(61,477
)
 
27,765

 
(33,712
)
Total
$
—

 
$
(13,770
)
 
$
(13,770
)
 
$
—

 
$
44,291

 
$
44,291


Note 6 - Commitments and Contingencies

Legal Proceedings

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

Environmental

Due to the nature of the oil and gas industry, this Partnership is exposed to environmental risks. The Managing General Partner has various policies and procedures in place to prevent environmental contamination and mitigate the risks from environmental contamination. The Managing General Partner conducts periodic reviews to identify changes in this Partnership's environmental risk profile. Liabilities are accrued when environmental remediation efforts are probable and the costs can be reasonably estimated. These liabilities are reduced as remediation efforts are completed or are adjusted as a consequence of subsequent periodic reviews. Liabilities for environmental remediation efforts are included in line item captioned “Accounts payable and accrued expenses” on the condensed balance sheet.

During the six months ended June 30, 2013, as a result of the Managing General Partner's periodic review, no new environmental remediation liabilities were identified and this Partnership's expense for environmental remediation efforts was not significant. This Partnership's environmental remediation effort liabilities as of June 30, 2013 and December 31, 2012 were not significant.

The Managing General Partner is not currently aware of any environmental claims existing as of June 30, 2013 which have not been provided for or would otherwise have a material impact on this Partnership's condensed financial statements; however, there can be no assurance that current regulatory requirements will not change or unknown past non-compliance with environmental laws will not be discovered on this Partnership's properties.

- 9-
PDC 2002-B LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
June 30, 2013
(unaudited)



Note 7 - Asset Retirement Obligations

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

 
Amount
 
 
Balance at December 31, 2012
$
223,265

Accretion expense
7,271

Obligations discharged with disposal of properties
(66,755
)
Balance at June 30, 2013
$
163,781

 
 
 

- 10-
PDC 2002-B LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
June 30, 2013
(unaudited)

Note 8 - Divestitures and Discontinued Operations

Piceance Basin. In February 2013, this Partnership's Managing General Partner entered into a purchase and sale agreement ("PSA") with certain affiliates of Caerus Oil and Gas LLC (“Caerus”), pursuant to which this Partnership agreed to sell to Caerus all of its Piceance Basin assets and certain derivatives. Under the same PSA, PDC agreed to sell to Caerus the Piceance Basin assets of PDC and certain other PDC-sponsored partnerships and certain other non-core Colorado oil and gas properties, leasehold mineral interests and related assets. In June 2013, this divestiture was completed with total consideration for this Partnership of approximately $435,000, subject to customary post-closing adjustments. The sale resulted in a gain on divestiture of assets of approximately $202,000. The Managing General Partner distributed a portion of the proceeds from the asset divestiture for distributions to its Partners in July 2013. See Note 9, Subsequent Events, for additional information regarding the use of proceeds received from the Piceance Basin asset sale.
Following the sale, this Partnership does not have a significant continuing involvement in the operations of, or cash flows from, the Piceance Basin oil and gas properties. Accordingly, the results of operations related to these assets have been separately reported as discontinued operations in the unaudited condensed statement of operations for all periods presented.
The following table presents statement of operations data related to this Partnership's discontinued operations for the Piceance Basin divestiture:
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
Statement of Operations - Discontinued Operations
 
2013
 
2012
 
2013
 
2012
 
 
 
 
 
 
 
 
 
Revenues:
 
 
 
 
 
 
 
 
Crude oil, natural gas and NGLs sales
 
$
41,326

 
$
40,246

 
$
80,126

 
$
65,770

 
 
 
 
 
 
 
 
 
Operating costs and expenses:
 
 
 
 
 
 
 
 
Crude oil, natural gas and NGLs production costs
 
26,237

 
10,838

 
51,369

 
101,644

Depreciation, depletion and amortization
 
—

 
11,304

 
6,356

 
21,591

Direct costs - general and administrative expense
 
13,774

 
—

 
13,774

 
—

Accretion of asset retirement obligations
 
673

 
952

 
1,670

 
1,890

Gain on sale of crude oil and natural gas properties
 
(201,633
)
 
—

 
(201,633
)
 
—

Total operating costs and expenses
 
(160,949
)
 
23,094

 
(128,464
)
 
125,125

 
 
 
 
 
 
 
 
 
Income (loss) from discontinued operations
 
$
202,275

 
$
17,152

 
$
208,590

 
$
(59,355
)
 
 
 
 
 
 

 


While the reclassification of revenues and expenses related to discontinued operations for the prior period had no impact upon previously reported net earnings, the statement of operations table presents the revenues and expenses that were reclassified from the specified statement of operations line items to discontinued operations.


Note 9 - Subsequent Events

In July 2013, this Partnership distributed a portion of the proceeds in the amount of $235,000 received for the Piceance Basin asset divestiture to the Partners as follows:
 
Amount
 
 
Managing General Partner
$
47,000

Investor Partners
188,000

Total
$
235,000

 
 

- 11-
PDC 2002-B LIMITED PARTNERSHIP
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
June 30, 2013
(unaudited)



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

Partnership Overview

PDC 2002-B Limited Partnership engages in the development, production and sale of crude oil, natural gas and NGLs. This Partnership began crude oil and natural gas operations in September 2002 and operates 11 gross (9.8 net) productive wells located in the Wattenberg Field of Colorado. The Managing General Partner markets this Partnership's crude oil and natural gas production to midstream marketers. Crude oil, natural gas and NGLs are sold primarily under market-sensitive contracts in which the price varies as a result of market forces. PDC does not charge a separate fee for the marketing of the crude oil, natural gas and NGLs because these services are covered by the monthly well operating charge. PDC, on behalf of this Partnership in accordance with the D&O Agreement, is authorized to enter into multi-year fixed price contracts and/or to 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, costs incurred and availability of PDC or third-party owned pipeline capacity, and other factors such as high pressures in the gathering system whether caused by heat or third-party facilities issues, may impact this Partnership's results. In addition, both sales volumes and prices tend to be affected by demand factors with a seasonal component.

Due to the Investor Partners' average annual rate of return being less than 12.8% in November 2009, this Partnership modified the standard ownership-based pro-rata allocation of Partnership cash available for distribution. This modified distribution ended in February 2013. See Note 1, General and Basis of Presentation, to the unaudited condensed financial statements included in this report and "Financial Condition, Liquidity and Capital Resources - Cash Flows" below for additional information and the effect of this modification on distributions.

Recent Developments

Crude Oil and Natural Gas Properties Divestiture

In February 2013, this Partnership's Managing General Partner entered into a purchase and sale agreement with certain affiliates of Caerus Oil and Gas LLC ("Caerus"), pursuant to which this Partnership agreed to sell to Caerus all of its Piceance Basin assets and certain derivatives. Under the same PSA, PDC agreed to sell to Caerus the Piceance Basin assets of PDC and certain other PDC-sponsored partnerships and certain other non-core Colorado oil and gas properties, leasehold mineral interests and related assets. In June 2013, this divestiture was completed with total consideration to this Partnership of approximately $435,000, subject to customary post-closing adjustments. The sale resulted in a gain on divestiture of assets of approximately $202,000. The effective date of this transaction was January 1, 2013. Following the sale to Caerus, this Partnership does not have continuing involvement in the operations of, or cash flows from, the Piceance Basin oil and gas properties. Accordingly, the results of operations related to these assets have been separately reported as discontinued operations in the unaudited condensed statement of operations for all periods presented. In July 2013, this Partnership distributed a portion of the proceeds of the sale to its Partners on a pro rata basis.

Partnership Operating Results Overview

Crude oil, natural gas and NGLs sales from continuing operations decreased 32%, or approximately $44,000, for the first six months of 2013 compared to the first six months of 2012, while sales volumes from continuing operations declined 34% period-to-period. The average sales price per barrel of crude oil equivalent ("Boe"), excluding the impact of realized derivative gains, was $50.43 for the current period compared to $48.95 for the same period a year ago. Realized gains from all natural gas derivatives, including net gains from the sale of this Partnership's remaining derivative positions in late June, contributed approximately $59,000 to total revenues for the first six months of 2013 compared to approximately $78,000 from natural gas derivatives for the first six months of 2012.

- 12-
PDC 2002-B LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)



Results of Operations

Summary Operating Results

The following table presents selected information regarding this Partnership’s results from continuing operations:
 
Three months ended June 30,
 
Six months ended June 30,
 
2013
 
2012
 
 Change
 
2013
 
2012
 
 Change
Number of gross producing wells (end of period)
11

 
11

 
—

 
11

 
11

 
—

 
 
 
 
 
 
 
 
 
 
 
 
Production(1)
 
 
 
 
 
 
 
 
 
 
 
Crude oil (Bbl)
275

 
653

 
(58
)%
 
756

 
1,219

 
(38
)%
Natural gas (Mcf)
2,160

 
2,872

 
(25
)%
 
4,700

 
7,352

 
(36
)%
NGLs (Bbl)
147

 
111

 
32
 %
 
320

 
376

 
(15
)%
Crude oil equivalent (Boe)(2)
782

 
1,243

 
(37
)%
 
1,859

 
2,821

 
(34
)%
Average Boe per day
9

 
14

 
(37
)%
 
10

 
16

 
(34
)%
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil, natural gas and NGLs sales
 
 
 
 
 
 
 
 
 
 
 
Crude oil
$
24,401

 
$
51,313

 
(52
)%
 
$
65,849

 
$
105,037

 
(37
)%
Natural gas
7,984

 
5,230

 
53
 %
 
15,500

 
17,031

 
(9
)%
NGLs
5,127

 
5,899

 
(13
)%
 
12,406

 
16,018

 
(23
)%
Total crude oil, natural gas and NGLs sales
$
37,512

 
$
62,442

 
(40
)%
 
$
93,755

 
$
138,086

 
(32
)%
 
 
 
 
 
 
 
 
 
 
 
 
Realized gain on derivatives, net
 
 
 
 
 
 
 
 
 
 
 
Natural gas
$
32,563

 
$
43,615

 
(25
)%
 
$
58,713

 
$
78,003

 
(25
)%
Total realized gain on derivatives, net
$
32,563

 
$
43,615

 
(25
)%
 
$
58,713

 
$
78,003

 
(25
)%
 
 
 
 
 
 
 
 
 
 
 
 
Average selling price (excluding realized gain on derivatives)
 
 
 
 
 
 
 
 
 
 
 
Crude oil (per Bbl)
$
88.73

 
$
78.58

 
13
 %
 
$
87.10

 
$
86.17

 
1
 %
Natural gas (Mcf)
3.70

 
1.82

 
103
 %
 
3.30

 
2.32

 
42
 %
NGLs (Bbl)
34.88

 
53.14

 
(34
)%
 
38.77

 
42.60

 
(9
)%
Crude oil equivalent (per Boe)
47.97

 
50.23

 
(4
)%
 
50.43

 
48.95

 
3
 %
 
 
 
 
 
 
 
 
 
 
 
 
Average cost per Boe
 
 
 
 
 
 
 
 
 
 
 
Crude oil, natural gas and NGLs production cost(3)
$
28.83

 
$
15.75

 
83
 %
 
$
28.32

 
$
14.76

 
92
 %
Depreciation, depletion and amortization
16.32

 
30.89

 
(47
)%
 
16.32

 
30.88

 
(47
)%
 
 
 
 
 
 
 
 
 
 
 
 
Operating costs and expenses
 
 
 
 
 
 
 
 
 
 
 
Direct costs - general and administrative
$
32,625

 
$
31,038

 
5
 %
 
$
63,611

 
$
59,896

 
6
 %
Depreciation, depletion and amortization
12,760

 
38,400

 
(67
)%
 
30,334

 
87,121

 
(65
)%
 
 
 
 
 
 
 
 
 
 
 
 
Cash distributions
$
8,321

 
$
8,466

 
(2
)%
 
$
15,555

 
$
17,865

 
(13
)%

Amounts may not recalculate due to rounding.
   

_______________
(1) Production is net and determined by multiplying the gross production volume of properties in which this Partnership has an interest by the average percentage of the leasehold or other property interest this Partnership owns.
(2) One Bbl of crude oil or NGL equals six Mcf of natural gas.
(3) Represents crude oil, natural gas and NGLs operating expenses, including production taxes.


- 13-
PDC 2002-B LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)




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

Bbl - One barrel of crude oil or natural gas liquids ("NGLs") or 42 gallons of liquid volume.
Boe - Barrels of crude oil equivalent.
MBbl - One thousand barrels of crude oil or NGLs.
Mcf - One thousand cubic feet of natural gas volume.
MMBtu - One million British thermal units.
MMcf - One million cubic feet of natural gas volume.


Crude Oil, Natural Gas and NGLs Sales

Crude Oil, Natural Gas and NGLs Pricing. This Partnership's results of operations depend upon many factors, particularly the price of crude oil, natural gas and NGLs and the Managing General Partner's ability to market this Partnership's production effectively. Crude oil, natural gas and NGLs prices are among the most volatile of all commodity prices. These price variations can have a material impact on this Partnership's financial results and capital expenditures.

Crude oil pricing is predominately driven by the physical market, supply and demand, the financial markets and national and international politics. The majority of this Partnership's crude oil is sold on a calendar-year basis at a fixed differential to NYMEX pricing. Natural gas prices vary by region and locality, depending upon the distance to markets, availability of pipeline capacity and supply and demand relationships in that region or locality. The price this Partnership receives for its natural gas produced is based on the Colorado Interstate Gas ("CIG") price. This Partnership's NGLs price is mainly based on prices from the Conway hub in Kansas where the Wattenberg production is marketed.

This Partnership currently uses the "net-back" method of accounting for these arrangements related to its natural gas sales. This Partnership sells natural gas at the wellhead and collects a price and recognizes revenues based on the wellhead sales price as transportation costs downstream of the wellhead are incurred by the purchaser and reflected in the wellhead price. The net-back method results in the recognition of a sales price that is below the indices for which the production is based.

During the spring and summer of 2012 and the latter part of the second quarter of 2013 and, to a lesser extent, in some other recent periods, this Partnership's Wattenberg Field production has been adversely impacted by increasing line pressures on the gathering system operated by this Partnership's third-party service provider. The continued acceleration of industry drilling activity, combined with higher temperatures in some periods, have resulted in reduced system compressor efficiency and increased line pressures in the Wattenberg Field. The curtailments that have occurred to date in 2013 are consistent with what the Managing General Partner expected to occur during this period. The Managing General Partner is working closely with the primary midstream provider in the Wattenberg Field who is implementing a multi-year facility expansion capable of significantly increasing long-term gathering and processing capacity. Initial system improvements have already been implemented with the startup of a new field compressor station, as well as installation and commissioning of gas bypass facilities at two gas processing plants in May and June of 2013. These projects increased midstream system capacity and have helped to mitigate the impact of increased production volumes on system pressures. The Managing General Partner expects reduced line pressures to substantially benefit this Partnership in late 2013, concurrent with the startup of the LaSalle gas plant and associated field compressor stations. Like most producers, this Partnership relies on its third-party midstream service providers to construct compression, gathering and processing facilities to keep pace with production growth. As a result, the timing and availability of these facilities is beyond this Partnership's or the Managing General Partner's control.


- 14-
PDC 2002-B LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)


Six months ended June 30, 2013 as compared to six months ended June 30, 2012

For the six months ended June 30, 2013 compared to the same period in 2012, crude oil, natural gas and NGLs production from continuing operations, on an energy equivalency-basis, decreased 34%, primarily due to normal production declines for this stage in the wells’ production life cycle and a decrease in production precipitated by curtailments due to high line pressure in the Wattenberg Field.

The approximate $44,000, or 32%, decrease in sales from continuing operations for the 2013 six month period as compared to the prior year period was a reflection of sales volume decreases of 34%. The average sales price per Boe, excluding the impact of realized derivative gains, was $50.43 for the current year six month period compared to $48.95 for the same period a year ago.
Crude oil, NGLs and natural gas sales from continuing operations for the six months ended June 30, 2013 decreased by 37%, 23%, and 9% respectively, as compared to the six months ended June 30, 2012. The crude oil sales decrease was due primarily to a sales volume decrease of 38%. The decrease in NGLs sales was due to a decrease of 15% in NGLs production volumes and by a decrease in the average commodity price per Bbl of 9%. The decrease in natural gas sales resulted from lower natural gas production volumes of 36%, partially offset by increased prices per Mcf of 42%.

Three months ended June 30, 2013 as compared to three months ended June 30, 2012

For the three months ended June 30, 2013 compared to the same period in 2012, crude oil, natural gas and NGLs production from continuing operations, on an energy equivalency-basis, decreased 37%, primarily due to normal production declines for this stage in the wells’ production life cycle and a decrease in production precipitated by curtailments due to high line pressure in the Wattenberg Field.

The approximate $25,000, or 40%, decrease in sales from continuing operations for the 2013 three month period as compared to the prior year period was a reflection of sales volume decreases of 37% and a decline in the average sales price per Boe of 4%. The average sales price per Boe, excluding the impact of realized derivative gains, was $47.97 for the current year three month period compared to $50.23 for the same period a year ago.
Crude oil and NGLs sales from continuing operations for the three months ended June 30, 2013 decreased by 52% and 13%, respectively, partially offset by increased natural gas sales of 53% as compared to the three months ended June 30, 2012. The decrease in crude oil sales was due primarily to a sales volume decrease of 58%, offset in part by an increase in the average commodity price per Bbl of 13%. The decrease in NGLs sales was due to a decrease in the average commodity price per Bbl of 34%, partially offset by a 32% increase in NGLs production volumes. The increase in natural gas sales resulted from increased prices per Mcf of 103%, partially offset by lower natural gas production volumes of 25%.

Commodity Price Risk Management

This Partnership used various derivative instruments to manage fluctuations in natural gas prices. In late June, derivative instruments that were due to mature subsequent to June 30, 2013 were liquidated, which resulted in an approximate $14,000 net realized gain. Realized gains on natural gas, exclusive of basis swaps, of approximately $27,000 were offset by realized losses of approximately $13,000 on this Partnership's basis swap positions. As of June 30, 2013, this Partnership did not have any derivative instruments in place for its future production. Currently, the Managing General Partner does not anticipate entering into derivative instruments for any of this Partnership's future production.

This Partnership had in place collars, fixed-price swaps and/or basis swaps on a portion of this Partnership's estimated natural gas production. This Partnership sold its natural gas at similar prices to the indices inherent in this Partnership's derivative instruments. As a result, for the volumes underlying this Partnership's derivative positions, this Partnership ultimately realized a price related to its collars of no less than the floor and no more than the ceiling and, for this Partnership's commodity swaps, this Partnership ultimately realized the fixed price related to its swaps.

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


- 15-
PDC 2002-B LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)


The following table presents the realized and unrealized derivative gains and losses included in commodity price risk management gain (loss), net:
 
Three months ended June 30,
 
Six months ended June 30,
 
2013
 
2012
 
2013
 
2012
Commodity price risk management gain (loss), net:
 
 
 
 
 
 
 
  Realized gains
 
 
 
 
 
 
 
  Natural gas
$
32,563

 
$
43,615

 
$
58,713

 
$
78,003

       Total realized gains, net
32,563

 
43,615

 
58,713

 
78,003

  Unrealized gains (losses)
 
 
 
 
 
 
 
Reclassification of realized gains included in
 
 
 
 
 
 
 
   prior periods unrealized gains
(26,388
)
 
(44,293
)
 
(72,483
)
 
(61,477
)
Unrealized gains (losses) for the period
—

 
(16,155
)
 
—

 
27,765

Total unrealized losses, net
(26,388
)
 
(60,448
)
 
(72,483
)
 
(33,712
)
Total commodity price risk management gain (loss), net
$
6,175

 
$
(16,833
)
 
$
(13,770
)
 
$
44,291


Six months ended June 30, 2013 as compared to six months ended June 30, 2012

Realized gains of approximately $59,000 recognized in the six months ended June 30, 2013 were primarily the result of lower natural gas spot prices at settlement compared to the respective strike price of this Partnership's natural gas derivative positions. For the six months ended June 30, 2013, realized gains on natural gas, exclusive of basis swaps, were approximately $114,000. These gains were offset in part by realized losses of approximately $55,000 on this Partnership's basis swap positions as the negative basis differential between NYMEX and CIG weighted-average price was narrower than the strike price of this Partnership's basis swaps.

Realized gains of approximately $78,000 recognized in the six months ended June 30, 2012 were primarily the result of lower natural gas spot prices at settlement compared to the respective strike price of this Partnership's natural gas derivative positions. For the six months ended June 30, 2012, realized gains on natural gas, exclusive of basis swaps, were approximately $126,000. These gains were offset in part by realized losses of approximately $48,000 on this Partnership's basis swap positions as the negative basis differential between NYMEX and CIG weighted-average price was narrower than the strike price of this Partnership's basis swaps.

Unrealized gains of approximately $28,000 for the six months ended June 30, 2012 were primarily related to the downward shift in the natural gas forward curve and its impact on the fair value of this Partnership's open positions, offset in part by the narrowing of the CIG basis forward curve. For the period ended June 30, 2012, unrealized gains on this Partnership's natural gas positions were approximately $32,000, offset by unrealized losses on this Partnership's CIG basis swaps of approximately $4,000.

Three months ended June 30, 2013 as compared to three months ended June 30, 2012

Realized gains of $33,000 recognized in the three months ended June 30, 2013 were primarily the result of lower natural gas spot prices at settlement compared to the respective strike price of this Partnership's natural gas derivative positions. For the three months ended June 30, 2013, realized gains on natural gas, exclusive of basis swaps, were $66,000. These gains were offset in part by realized losses of $33,000 on this Partnership's basis swap positions as the negative basis differential between NYMEX and CIG weighted-average price was narrower than the strike price of this Partnership's basis swaps.

Realized gains of approximately $44,000 recognized in the three months ended June 30, 2012 were primarily the result of lower natural gas spot prices at settlement compared to the respective strike price of this Partnership's natural gas derivative positions. For the three months ended June 30, 2012, realized gains on natural gas, exclusive of basis swaps, were approximately $66,000. These gains were offset in part by realized losses of $22,000 on this Partnership's basis swap positions as the negative basis differential between NYMEX and CIG weighted-average price was narrower than the strike price of this Partnership's basis swaps.

Unrealized losses of approximately $16,000 for the three months ended June 30, 2012 were primarily related to the upward shift in the natural gas forward curve and its impact on the fair value of this Partnership's open positions and by the narrowing of the CIG basis forward curve. For the period ended June 30, 2012, unrealized losses on this Partnership's natural gas positions were approximately $13,000 in addition to unrealized losses on this Partnership's CIG basis swaps of approximately $3,000.


- 16-
PDC 2002-B LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)



Crude Oil, Natural Gas and NGLs Production Costs

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

Six months ended June 30, 2013 as compared to six months ended June 30, 2012

Crude oil, natural gas and NGLs production costs for the six months ended June 30, 2013 increased approximately $11,000 compared to the same period in 2012 as increased operating costs were partially offset by decreased production taxes in 2013 consistent with sales declines from 2012. Crude oil, natural gas and NGLs production costs per Boe increased to $28.32 during 2013 from $14.76 in 2012 due to lower volumes.

Three months ended June 30, 2013 as compared to three months ended June 30, 2012

Crude oil, natural gas and NGLs production costs for the three months ended June 30, 2013 were level compared to the same period in 2012 as slightly increased operating costs were offset by decreased production taxes in 2013 consistent with sales declines from 2012. Crude oil, natural gas and NGLs production costs per Boe increased to $28.83 during 2013 from $15.75 in 2012 due to lower volumes.

Depreciation, Depletion and Amortization

Six months ended June 30, 2013 as compared to six months ended June 30, 2012

Depreciation, depletion and amortization ("DD&A") expense related to crude oil and natural gas properties is directly related to proved reserves and production volumes. DD&A expense for continuing operations decreased approximately $57,000 for the six months ended June 30, 2013 compared to the six months ended June 30, 2012 due to lower production volumes and by a decreased DD&A expense rate in 2013. The DD&A expense rate per Boe decreased to $16.32 for the 2013 six months compared to $30.88 during the same period in 2012 due to the effect of an impairment recorded for the Wattenberg Field assets as of December 31, 2012.

Three months ended June 30, 2013 as compared to three months ended June 30, 2012

DD&A expense for continuing operations decreased approximately $26,000 for the three months ended June 30, 2013 compared to the three months ended June 30, 2012 due to lower production volumes and by a decreased DD&A expense rate in 2013. The DD&A expense rate per Boe decreased to $16.32 for the 2013 three months compared to $30.89 during the same period in 2012 due to the effect of an impairment recorded for the Wattenberg Field assets as of December 31, 2012.

Discontinued Operations

In February 2013, the Managing General Partner entered into a purchase and sale agreement with Caerus, pursuant to which this Partnership agreed to sell to Caerus its Piceance Basin assets and certain derivatives. In June 2013, this divestiture was completed with total consideration to this Partnership of approximately $435,000, subject to customary post-closing adjustments. The sale resulted in a gain on divestiture of assets of $202,000. The effective date of the transaction was January 1, 2013. Following the sale to Caerus, this Partnership does not have significant continuing involvement in the operations of, or cash flows from, the Piceance Basin assets. Accordingly, the results of operations related to these assets have been separately reported as discontinued operations in the unaudited condensed statement of operations for all periods presented. See Note 8, Divestitures and Discontinued Operations, to the accompanying unaudited condensed financial statements included elsewhere in this report for additional information regarding the sale of this Partnership's Piceance Basin assets.


- 17-
PDC 2002-B LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)


The table below presents production data related to this Partnership's Piceance Basin assets that have been divested and that are classified as discontinued operations:

 
Three Months Ended June 30,
 
Six Months Ended June 30,
Discontinued Operations
2013
 
2012
 
2013
 
2012
Production
 
 
 
 
 
 
 
Crude oil (Bbl)
7

 
281

 
17

 
291

Natural gas (Mcf)
12,118

 
14,942

 
26,020

 
30,030

Crude oil equivalent (Boe)
2,027

 
2,771

 
4,354

 
5,296



Financial Condition, Liquidity and Capital Resources

This Partnership's primary source of liquidity has been cash flows from operating activities. This source of cash has been primarily used to fund this Partnership's operating costs, direct costs-general and administrative and monthly distributions to the Investor Partners and the Managing General Partner. For the six months ended June 30, 2013, in addition to the $16,000 net cash flows from operating activities, this Partnership's liquidity was enhanced by the gross proceeds received from the sale of the Piceance Basin assets of approximately $435,000.

Fluctuations in this Partnership's operating cash flows are substantially driven by changes in commodity prices, sales volumes and, historically, realized gains and losses from commodity contracts. Commodity prices have historically been volatile and, through June 30, 2013, the Managing General Partner attempted to manage this volatility through the use of derivatives. Therefore, historically, the primary source of cash flows from operations became the net activity between crude oil, natural gas and NGLs sales and realized natural gas derivative gains and losses. This Partnership has no crude oil, natural gas or NGLs derivative positions at June 30, 2013 as all open positions were either sold to Caerus pursuant to the Piceance Basin asset divestiture or liquidated during the three months ended June 30, 2013. See Results of Operations for further discussion of the impact of prices and volumes on sales from operations and the impact of derivative activities on this Partnership's revenues through June 30, 2013.

This Partnership's future operations are expected to be conducted with available funds and revenues generated from crude oil, natural gas and NGLs production activities. Crude oil, natural gas and NGLs production from existing properties are generally expected to continue a gradual decline in the rate of production over the remaining life of the wells. Therefore, this Partnership anticipates a lower annual level of crude oil, natural gas and NGLs production and, in the absence of significant price increases or additional reserve development, lower revenues. This Partnership also expects cash flows from operations to decline if commodity prices remain at current levels or decrease in the future. Under these circumstances, decreased production would have a material adverse impact on this Partnership's operations and may result in reduced cash distributions to the Managing General Partner and Investor Partners through the remainder of 2013 and beyond, and may substantially reduce or restrict this Partnership's ability to participate in Additional Development Plan activities.


- 18-
PDC 2002-B LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)



Working Capital

At June 30, 2013, this Partnership had working capital of approximately $435,000, compared to working capital of approximately $84,000 at December 31, 2012. The increase of approximately $351,000 was primarily due to the following changes:

•
cash and cash equivalents increased, primarily due to the sale of the Piceance Basin assets to Caerus, by approximately $435,000 between June 30, 2013 and December 31, 2012;
•
accounts receivable increased by approximately $16,000 between June 30, 2013 and December 31, 2012;
•
realized and unrealized derivative gains receivable decreased by approximately $101,000 between June 30, 2013 and December 31, 2012;
•
oil inventory decreased by approximately $16,000 between June 30, 2013 and December 31, 2012;
•
accounts payable and accrued expenses increased by approximately $21,000 between June 30, 2013 and December 31, 2012; and
•
amounts due to Managing General Partner-other, net, excluding crude oil, natural gas and NGLs sales received from third parties and realized derivative gains, decreased by approximately $38,000 between June 30, 2013 and December 31, 2012.

Additional Development Plan activities have been suspended. If the Additional Development Plan commences, funding will be provided by the withholding of distributable cash flows from the Managing General Partner and Investor Partners. Future working capital balances are expected to fluctuate by increasing during periods of Additional Development Plan funding and decreasing during periods when payments are made for refracturing or recompletion activities.

Cash Flows

Operating Activities

This Partnership's cash flows from operating activities were primarily impacted by commodity prices, production volumes, realized gains and losses from derivative positions, operating costs and direct costs-general and administrative expenses. The key components for the changes in this Partnership's cash flows from operating activities are described in more detail in Results of Operations above.

Net cash flows from operating activities were $16,000 for the six months ended June 30, 2013 compared to $21,000 for the comparable period in 2012. The decrease of $5,000 in cash from operating activities was due primarily to the following:

•
a decrease in crude oil, natural gas and NGLs sales receipts of approximately $72,000 ;
•
an increase in commodity price risk management realized gain receipts of approximately $2,000; and
•
a decrease in production costs and direct costs-general and administrative payments of approximately $65,000.

Investing Activities

Cash flows from investing activities primarily consist of proceeds received from the dispositions of crude oil and natural gas properties, offset by investments in equipment and services. During the six months ended June 30, 2013, proceeds from the dispositions of crude oil and natural gas properties were approximately $435,000. From time to time, this Partnership invests in equipment which supports treatment, delivery and measurement of crude oil, natural gas and NGLs or environmental protection.

- 19-
PDC 2002-B LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)


Financing Activities

This Partnership initiated monthly cash distributions to investors in March 2003 and has distributed $9.6 million through June 30, 2013. The table below presents cash distributions to this Partnership's investors. Distributions to the Managing General Partner represent amounts distributed to the Managing General Partner for its 20% general partner interest in this Partnership and Investor Partner distributions include amounts distributed to Investor Partners for their 80% ownership share in this Partnership, as well as amounts distributed to the Managing General Partner for limited partnership units repurchased.
Distributions
 
 
 
 
 
 
 
Three months ended June 30,
 
Managing General Partner
 
Investor Partners
 
Total
2013
 
$
1,926

 
$
6,395

 
$
8,321

2012
 
852

 
7,614

 
8,466

 
 
 
 
 
 
 
Six months ended June 30,
 
Managing General Partner
 
Investor Partners
 
Total
2013
 
$
2,453

 
$
13,102

 
$
15,555

2012
 
1,802
 
16,063
 
17,865


Six months ended June 30, 2013 as compared to six months ended June 30, 2012

The decrease in distributions for the six months ended June 30, 2013 as compared to 2012 is primarily due to a decrease in cash flows from operating activities during 2013. The Investor Partners received proportionally less in 2013 due to the expiration of Preferred Cash Distributions discussed below.

Three months ended June 30, 2013 as compared to three months ended June 30, 2012

Total distributions for the three months ended June 30, 2013 were level compared to 2012. The Investor Partners received proportionally less in 2013 due to the expiration of Preferred Cash Distributions discussed below.

In July 2013, this Partnership distributed proceeds received for the Piceance Basin asset divestiture of approximately $235,000 including approximately $188,000 and $47,000 to the Investor Partners and the Managing General Partner, respectively.

Beginning in November 2009, when the Investor Partners' average annual rate of return fell below 12.8%, this Partnership modified the standard ownership-based pro-rata allocation of Partnership cash available for distribution, pursuant to the Performance Standard Obligation outlined in Section 4.02 of the Agreement. Distributions paid to the Managing General Partner were reduced and distributions to the Investor Partners were increased by $668 and $1,771 for the six months ended June 30, 2013 and 2012, respectively, as a result of the Preferred Cash Distribution made under the terms in Section 4.02. The Managing General Partner's obligation under Section 4.02 expired in February 2013. For more information concerning the Performance Standard Obligation, see Note 8, Partners' Equity and Cash Distributions, to this Partnership's financial statements included in the 2012 Form 10-K.

Off-Balance Sheet Arrangements

As of June 30, 2013, this Partnership had no existing off-balance sheet arrangements, as defined under SEC rules, which have or are reasonably likely to have a material current or future effect on this Partnership's financial condition, results of operations, liquidity, capital expenditures or capital resources.

Commitments and Contingencies

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


- 20-
PDC 2002-B LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)


Recent Accounting Standards

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

Critical Accounting Policies and Estimates

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

There have been no significant changes to this Partnership's critical accounting policies and estimates or in the underlying accounting assumptions and estimates used in these critical accounting policies from those disclosed in the financial statements and accompanying notes contained in this Partnership's 2012 Form 10-K.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Not applicable.

Item 4. Controls and Procedures

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

(a)    Evaluation of Disclosure Controls and Procedures

As of June 30, 2013, PDC, as Managing General Partner on behalf of this Partnership, carried out an evaluation, under the supervision and with the participation of the Managing General Partner's management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of this Partnership's disclosure controls and procedures pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e). This evaluation considered the various processes carried out under the direction of the Managing General Partner's disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports that this Partnership files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC's rules and forms, and that such information is accumulated and communicated to this Partnership's management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely discussion regarding required disclosure.

Based on the results of this evaluation, the Managing General Partner's Chief Executive Officer and the Chief Financial Officer concluded that this Partnership's disclosure controls and procedures were effective as of June 30, 2013.

(b)    Changes in Internal Control over Financial Reporting
 
During the three months ended June 30, 2013, PDC, the Managing General Partner, made no changes in this Partnership's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) that have materially affected or are reasonably likely to materially affect this Partnership's internal control over financial reporting. 

- 21-
PDC 2002-B LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)



PART II – OTHER INFORMATION

Item 1.    Legal Proceedings

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


Item 1A. Risk Factors

Not applicable.


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

Unit Repurchase Program. Beginning in March 2006, the third anniversary of the date of the first Partnership cash distributions, Investor Partners of this 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.

The following table presents information about the Managing General Partner's limited partner unit repurchases during the three months ended June 30, 2013:

Period
 
Total Number of
 Units Repurchased
 
Average Price Paid
 Per Unit
April 1-30, 2013
 
0.75

 
$
207

May 1-31, 2013
 
—

 
—

June 1-30, 2013
 
0.52

 
183

     Total
 
1.27

 
197



Item 3.    Defaults Upon Senior Securities

Not applicable.


Item 4.    Mine Safety Disclosures

Not applicable.


Item 5.    Other Information

None.

- 22-
PDC 2002-B LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)



Item 6. Exhibits Index
 
 
 
 
Incorporated by Reference
 
 
Exhibit
Number
 
Exhibit Description
 
Form
 
SEC File
Number
 
Exhibit
 
Filing Date
 
Filed
Herewith
 
 
 
 
 
 
 
 
 
 
 
 
 
10.1
 
Purchase and Sale Agreement by and among PDC Energy, Inc., affiliated partnerships and certain affiliates of Caerus Oil and Gas LLC, dated February 4, 2013.
 
10-Q
 
000-07246
 
10.1
 
5/1/2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
10.2
 
Amendment No. 1 to Purchase and Sale Agreement by and among PDC Energy, Inc., affiliated partnerships and certain affiliates of Caerus Oil and Gas LLC, dated May 30, 2013.
 
10-Q
 
000-07246
 
10.1
 
6/3/2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
31.1
 
Certification by Chief Executive Officer of PDC Energy, Inc., the Managing General Partner of this Partnership, pursuant to Rule 13a-14(a)/15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
 
 
 
 
 
 
 
X
 
 
 
 
 
 
 
 
 
 
 
 
 
31.2
 
Certification by Chief Financial Officer of PDC Energy, Inc., the Managing General Partner of this Partnership, pursuant to Rule 13a-14(a)/15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
 
 
 
 
 
 
 
X
 
 
 
 
 
 
 
 
 
 
 
 
 
32.1*
 
Certifications by Chief Executive Officer and Chief Financial Officer of PDC Energy, Inc., the Managing General Partner of this Partnership, pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
 
 
 
 
 
 
 
 

 
 
 
 
 
 
 
 
 
 
 
 
 
101.INS*
 
XBRL Instance Document
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
101.SCH*
 
XBRL Taxonomy Extension Schema Document
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
101.CAL*
 
XBRL Taxonomy Extension Calculation Linkbase Document
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
101.DEF*
 
XBRL Taxonomy Extension Definition Linkbase Document
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
101.LAB*
 
XBRL Taxonomy Extension Label Linkbase Document
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
101.PRE*
 
XBRL Taxonomy Extension Presentation Linkbase Document
 
 
 
 
 
 
 
 
 
 
*Furnished herewith.

- 23-
PDC 2002-B 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.

PDC 2002-B Limited Partnership
By its Managing General Partner
PDC Energy, Inc.

 
By: /s/ James M. Trimble
 
 
James M. Trimble
Chief Executive Officer and President
of PDC Energy, Inc.
 
 
August 14, 2013
 
 
 
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated:


Signature
 
Title
Date
 
 
 
 
/s/ James M. Trimble
 
Chief Executive Officer and President
August 14, 2013
James M. Trimble
 
PDC Energy, Inc.
Managing General Partner of the Registrant
 
 
 
(principal executive officer)
 
 
 
 
 
/s/ Gysle R. Shellum
 
Chief Financial Officer
August 14, 2013
Gysle R. Shellum
 
PDC Energy, Inc.
Managing General Partner of the Registrant
 
 
 
(principal financial officer)
 
 
 
 
 
/s/ R. Scott Meyers
 
Chief Accounting Officer
August 14, 2013
R. Scott Meyers
 
PDC Energy, Inc.
Managing General Partner of the Registrant
 
 
 
(principal accounting officer)
 
 

- 24-

PDC 2002 B LTD PARTNERSHIP Reports