PDCE 2013 3.31 10Q
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 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 March 31, 2013

or

£ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from __________ to _________

Commission File Number 000-07246
PDC ENERGY, INC.
(Exact name of registrant as specified in its charter)

Nevada
95-2636730
(State of incorporation)
(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 T 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 T 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  x
Accelerated filer  o
Non-accelerated filer  £
(Do not check if a smaller reporting company)
Smaller reporting company  o

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

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: 30,341,302 shares of the Company's Common Stock ($0.01 par value) were outstanding as of April 19, 2013.


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PDC ENERGY, INC.


TABLE OF CONTENTS

 
PART I - FINANCIAL INFORMATION
 
Page
 
 
 
 
Item 1.
Financial Statements
 
 
 
 
 
 
 
 
 
 
Item 2.
 
Item 3.
 
Item 4.
 
 
 
 
 
PART II – OTHER INFORMATION
 
 
 
 
Item 1.
 
Item 1A.
 
Item 2.
 
Item 3.
 
Item 4.
 
Item 5.
 
Item 6.
 
 
 
 
 
 
 




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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 our 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" 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 natural gas, natural gas liquids (“NGLs”) and crude oil reserves; future production (including the components of such production), expenses, cash flows and liquidity; anticipated capital projects, expenditures and opportunities; future exploration and development activities; availability of additional midstream facilities and services, the timing of that availability and related benefits to us; availability of sufficient funding for our capital program and sources of that funding; our and PDC Mountaineer, LLC's ("PDCM") compliance with debt covenants, the borrowing base under our credit facility and the renewal of a letter of credit under that facility; the future effect of contracts, policies and procedures we believe to be customary; effectiveness of our derivative program in providing a degree of price stability; closing of, and expected proceeds from, our pending asset disposition; and our 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 our good faith judgment, such statements can only be based on facts and factors currently known to us. Consequently, forward-looking statements are inherently subject to risks and uncertainties, including known and unknown risks and uncertainties incidental to the exploration for, and the acquisition, development, production and marketing of natural gas, NGLs and crude oil, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements.

Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:
changes in production volumes and worldwide demand, including economic conditions that might impact demand;
volatility of commodity prices for natural gas, NGLs and crude oil;
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 values of our natural gas and crude oil properties resulting in impairments;
changes in estimates of proved reserves;
inaccuracy of reserve estimates and expected production rates;
potential for production decline rates from our wells to be greater than expected;
timing and extent of our success in discovering, acquiring, developing and producing reserves;
our ability to acquire leases, drilling rigs, supplies and services at reasonable prices;
timing and receipt of necessary regulatory permits;
risks incidental to the drilling and operation of natural gas and crude oil wells;
our future cash flows, liquidity and financial condition;
competition in the oil and gas industry;
availability and cost of capital to us;
reductions in the borrowing base under our revolving credit facility;
availability of sufficient pipeline, gathering and other transportation facilities and related infrastructure to process and transport our production, particularly in the Wattenberg Field, and the impact of these facilities on the prices we receive for our production;
our success in marketing natural gas, NGLs and crude oil;
effect of natural gas and crude oil derivatives activities;
impact of environmental events, governmental and other third-party responses to such events, and our ability to insure adequately against such events;
cost of pending or future litigation;
effect that acquisitions we may pursue have on our capital expenditures;
potential obstacles to completing our pending asset disposition or other transactions, in a timely manner or at all, and purchase price or other adjustments relating to those transactions that may be unfavorable to us;
our ability to retain or attract senior management and key technical employees; and
success of strategic plans, expectations and objectives for our future operations.
 
Further, we urge you to carefully review and consider the cautionary statements and disclosures, specifically those under the heading "Risk Factors," made in this Quarterly Report on Form 10-Q, our 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 February 27, 2013, and our other filings with the SEC for further information on risks and uncertainties that could affect our business, financial condition, results of operations and prospects, which are incorporated by this reference as though fully set forth herein. We caution you not to place undue reliance on forward-looking statements, which speak only as of the date of this report. We undertake 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.


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REFERENCES

Unless the context otherwise requires, references in this report to "PDC Energy," "PDC," "the Company," "we," "us," "our," "ours" or "ourselves" refer to the registrant, PDC Energy, Inc. and all subsidiaries consolidated for the purposes of its financial statements, including our proportionate share of the financial position, results of operations, cash flows and operating activities of our affiliated partnerships and PDCM, a joint venture currently owned 50% each by PDC and Lime Rock Partners, LP, formed for the purpose of exploring and developing the Marcellus Shale formation in the Appalachian Basin. Unless the context otherwise requires, references in this report to "Appalachian Basin" includes PDC's proportionate share of our affiliated partnerships' and PDCM's assets, results of operations, cash flows and operating activities. See Note 1, Nature of Operations and Basis of Presentation, to our condensed consolidated financial statements included elsewhere in this report for a description of our consolidated subsidiaries.


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PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS

PDC ENERGY, INC.
Condensed Consolidated Balance Sheets
(unaudited; in thousands, except share and per share data)
 
 
March 31, 2013
 
December 31, 2012 (1)
Assets
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
2,494

 
$
2,457

Restricted cash
 
3,948

 
3,942

Accounts receivable, net
 
65,822

 
64,880

Accounts receivable affiliates
 
5,087

 
4,842

Fair value of derivatives
 
29,850

 
52,042

Deferred income taxes
 
37,573

 
36,151

Prepaid expenses and other current assets
 
7,885

 
7,635

Total current assets
 
152,659

 
171,949

Properties and equipment, net
 
1,375,473

 
1,616,706

Assets held for sale
 
216,802

 

Fair value of derivatives
 
5,181

 
6,883

Other assets
 
31,698

 
31,310

Total Assets
 
$
1,781,813

 
$
1,826,848

 
 
 
 
 
Liabilities and Shareholders' Equity
 
 
 
 
Liabilities
 
 
 
 
Current liabilities:
 
 
 
 
Accounts payable
 
$
70,471

 
$
82,716

Accounts payable affiliates
 
3,394

 
5,296

Production tax liability
 
26,709

 
25,899

Fair value of derivatives
 
23,564

 
18,439

Funds held for distribution
 
32,406

 
34,228

Accrued interest payable
 
21,688

 
11,056

Other accrued expenses
 
16,521

 
25,715

Total current liabilities
 
194,753

 
203,349

Long-term debt
 
687,970

 
676,579

Deferred income taxes
 
128,699

 
148,427

Asset retirement obligation
 
34,296

 
61,563

Fair value of derivatives
 
13,046

 
10,137

Liabilities held for sale
 
28,346

 

Other liabilities
 
28,798

 
23,612

Total liabilities
 
1,115,908

 
1,123,667

 
 
 
 
 
Commitments and contingent liabilities
 

 

 
 
 
 
 
Shareholders' equity
 
 
 
 
Preferred shares - par value $0.01 per share, 50,000,000 shares authorized, none issued
 

 

Common shares - par value $0.01 per share, 100,000,000 authorized, 30,337,524 and 30,294,224 issued as of March 31, 2013 and December 31, 2012, respectively
 
303

 
303

Additional paid-in capital
 
389,831

 
387,494

Retained earnings
 
276,150

 
315,568

Treasury shares - at cost, 8,788 and 5,059 as of March 31, 2013 and December 31, 2012, respectively
 
(379
)
 
(184
)
Total shareholders' equity
 
665,905

 
703,181

Total Liabilities and Shareholders' Equity
 
$
1,781,813

 
$
1,826,848

__________
(1) Derived from our audited 2012 balance sheet.


See accompanying Notes to Condensed Consolidated Financial Statements
1

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PDC ENERGY, INC.
Condensed Consolidated Statements of Operations
(unaudited; in thousands, except per share data)
 
 
Three Months Ended March 31,

 
2013
 
2012
Revenues:
 
 
 
 
Natural gas, NGLs and crude oil sales
 
$
79,439

 
$
66,955

Sales from natural gas marketing
 
13,670

 
11,381

Commodity price risk management gain (loss), net
 
(22,355
)
 
11,501

Well operations, pipeline income and other
 
1,072

 
1,169

Total revenues
 
71,826

 
91,006

Costs, expenses and other:
 
 
 
 
Production costs
 
15,858

 
12,936

Cost of natural gas marketing
 
13,736

 
11,091

Exploration expense
 
1,689

 
1,872

Impairment of natural gas and crude oil properties
 
46,459

 
588

General and administrative expense
 
15,115

 
14,708

Depreciation, depletion, and amortization
 
27,949

 
27,912

Accretion of asset retirement obligations
 
1,148

 
727

Gain on sale of properties and equipment
 
(38
)
 
(154
)
Total cost, expenses and other
 
121,916

 
69,680

Income (loss) from operations
 
(50,090
)
 
21,326

Interest expense
 
(13,357
)
 
(10,444
)
Interest income
 

 
2

Income (loss) from continuing operations before income taxes
 
(63,447
)
 
10,884

Provision for income taxes
 
22,492

 
(4,120
)
Income (loss) from continuing operations
 
(40,955
)
 
6,764

Income from discontinued operations, net of tax
 
1,537

 
9,071

Net income (loss)
 
$
(39,418
)
 
$
15,835

 
 
 
 
 
Earnings per share:
 
 
 
 
Basic
 
 
 
 
Income (loss) from continuing operations
 
$
(1.35
)
 
$
0.29

Income from discontinued operations
 
0.05

 
0.38

Net income (loss)
 
$
(1.30
)
 
$
0.67

 
 
 
 
 
Diluted
 
 
 
 
Income (loss) from continuing operations
 
$
(1.35
)
 
$
0.28

Income from discontinued operations
 
0.05

 
0.38

Net income (loss)
 
$
(1.30
)
 
$
0.66

 
 
 
 
 
Weighted-average common shares outstanding:
 
 
 
 
Basic
 
30,270

 
23,609

Diluted
 
30,270

 
23,889

 
 
 
 
 
 

See accompanying Notes to Condensed Consolidated Financial Statements
2

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PDC ENERGY, INC.
Condensed Consolidated Statements of Cash Flows
(unaudited; in thousands)
 
 
Three Months Ended March 31,
 
 
2013
 
2012
Cash flows from operating activities:
 
 
 
 
Net income (loss)
 
$
(39,418
)
 
$
15,835

Adjustments to net income (loss) to reconcile to net cash from operating activities:
 
 
 
 
Unrealized (gain) loss on derivatives, net
 
30,721

 
(1,533
)
Depreciation, depletion and amortization
 
30,207

 
39,814

Impairment of natural gas and crude oil properties
 
46,462

 
653

Accretion of asset retirement obligation
 
1,245

 
819

Stock-based compensation
 
2,602

 
1,946

Excess tax benefits from stock-based compensation
 
(242
)
 
(120
)
Gain on sale of properties and equipment
 
(38
)
 
(20,489
)
Amortization of debt discount and issuance costs
 
1,752

 
1,641

Deferred income taxes
 
(21,150
)
 
10,914

Other
 
206

 
230

Changes in assets and liabilities
 
(8,085
)
 
(5,411
)
Net cash from operating activities
 
44,262

 
44,299

Cash flows from investing activities:
 
 
 
 
Capital expenditures
 
(61,873
)
 
(107,029
)
Acquisition of oil and gas properties
 

 
(10,000
)
Proceeds from acquisition adjustments
 
7,579

 

Proceeds from sale of properties and equipment
 
38

 
184,646

Net cash from investing activities
 
(54,256
)
 
67,617

Cash flows from financing activities:
 
 
 
 
Proceeds from revolving credit facility
 
95,500

 
144,750

Payment of revolving credit facility
 
(85,000
)
 
(263,000
)
Payment of debt issuance costs
 
(14
)
 

Excess tax benefits from stock-based compensation
 
242

 
120

Purchase of treasury shares
 
(697
)
 
(369
)
Net cash from financing activities
 
10,031

 
(118,499
)
Net change in cash and cash equivalents
 
37

 
(6,583
)
Cash and cash equivalents, beginning of period
 
2,457

 
8,238

Cash and cash equivalents, end of period
 
$
2,494

 
$
1,655

 
 
 
 
 
Supplemental cash flow information:
 
 
 
 
Cash payments (receipts) for:
 
 
 
 
Interest, net of capitalized interest
 
$
1,196

 
$
14,975

Income taxes
 
2

 
(1,100
)
Non-cash investing activities:
 
 
 
 
Change in accounts payable related to purchases of properties and equipment
 
$
8,413

 
$
(21,044
)
Change in asset retirement obligation, with a corresponding change to natural gas and crude oil properties, net of disposals
 
98

 
(1,962
)

See accompanying Notes to Condensed Consolidated Financial Statements
3

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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2013
(Unaudited)


NOTE 1 - NATURE OF OPERATIONS AND BASIS OF PRESENTATION

PDC Energy, Inc. ("PDC," "PDC Energy," "we," "us" or "the Company") is a domestic independent crude oil, NGL and natural gas company engaged in the exploration for and the acquisition, development, production and marketing of crude oil, NGLs and natural gas . PDC is focused operationally on the liquid-rich Wattenberg Field in the DJ Basin and, in the Appalachian Basin, on the liquid-rich Utica Shale and the dry-gas Marcellus Shale. As of March 31, 2013, we owned an interest in approximately 7,300 gross wells located primarily in the Wattenberg Field, Appalachian Basin, Northeast Colorado ("NECO") and Piceance Basin. We are engaged in two business segments: (1) Oil and Gas Exploration and Production and (2) Gas Marketing.

The accompanying unaudited condensed consolidated financial statements include the accounts of PDC, our wholly owned subsidiaries, and our proportionate share of PDC Mountaineer, LLC ("PDCM") and our 21 affiliated partnerships. Pursuant to the proportionate consolidation method, our accompanying condensed consolidated financial statements include our pro rata share of assets, liabilities, revenues and expenses of the entities which we proportionately consolidate. All material intercompany accounts and transactions have been eliminated in consolidation.

In our opinion, the accompanying condensed consolidated financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary for a fair statement of our financial statements for interim periods in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in audited financial statements have been condensed or omitted. The information presented in this Quarterly Report on Form 10-Q should be read in conjunction with our audited consolidated financial statements and notes thereto included in our 2012 Form 10-K. Our results of operations and cash flows for the three months ended March 31, 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 planned sale of our Piceance Basin and NECO oil and gas properties. See Note 12, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information regarding the planned divestiture. We also reclassified prepaid well cost write-offs out of the statement of cash flows line item changes in assets and liabilities and into other. These reclassifications had no impact on previously reported cash flows, net income, earnings per share or shareholders' equity.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Recently Adopted Accounting Standards.

On January 1, 2013, we 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. Our adoption of these changes had no impact on the condensed consolidated financial statements.

NOTE 3 - FAIR VALUE OF FINANCIAL INSTRUMENTS

Derivative Financial Instruments

Determination of fair value. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us 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.


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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

We measure the fair value of our derivative instruments based on a pricing model that utilizes market-based inputs, including but not limited to the contractual price of the underlying position, current market prices, natural gas and crude oil forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our 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.

We validate our 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 we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. While we believe our 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.

We have evaluated the credit risk of the counterparties holding our derivative assets, which are primarily financial institutions who are also major lenders in our revolving credit facility, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our counterparties on the fair value of our derivative instruments is not significant.

Our fixed-price swaps, basis swaps and physical purchases are included in Level 2 and our natural gas and crude oil collars, natural gas calls and physical sales are included in Level 3. The following table presents, for each applicable level within the fair value hierarchy, our derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis:

 
March 31, 2013
 
December 31, 2012
 
Significant Other
Observable
Inputs
(Level 2)
  
Significant
Unobservable
Inputs
(Level 3)
  
Total
 
Significant Other
Observable
Inputs
(Level 2)
  
Significant
Unobservable
Inputs
(Level 3)
  
Total
 
(in thousands)
Assets:
 
 
 
 
 
 
 
 
 
 
 
Commodity-based derivative contracts
$
24,588

 
$
9,604

 
$
34,192

 
$
42,788

   
$
15,734

   
$
58,522

Basis protection derivative contracts
828

 
11

 
839

 
387

 
16

 
403

Total assets
25,416

 
9,615

 
35,031

 
43,175

 
15,750

 
58,925

Liabilities:
 
 
 
 
 
 
 
   
 
   
 
Commodity-based derivative contracts
22,531

 
1,952

 
24,483

 
9,839

 
2,081

   
11,920

Basis protection derivative contracts
12,127

 

 
12,127

 
16,656

 

   
16,656

Total liabilities
34,658

 
1,952

 
36,610

 
26,495

 
2,081

 
28,576

Net asset (liability)
$
(9,242
)
 
$
7,663

 
$
(1,579
)
 
$
16,680

 
$
13,669

 
$
30,349

 
 
 
 
 
 
 
 
 
 
 
 

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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

The following table presents a reconciliation of our Level 3 assets measured at fair value:

 
 
Three Months Ended March 31,
 
 
2013
 
2012
 
 
(in thousands)
 
 
 
 
 
Fair value, net asset, beginning of period
 
$
13,669

 
$
22,107

Changes in fair value included in statement of operations line item:
 
 
 
 
Commodity price risk management gain, net
 
(2,731
)
 
1,416

Sales from natural gas marketing
 
(16
)
 
43

Changes in fair value included in balance sheet line item:
 
 
 
 
Accounts payable affiliates (1)
 

 
(52
)
Settlements included in statement of operations line items:
 
 
 
 
Commodity price risk management loss, net
 
(3,234
)
 
(3,797
)
Sales from natural gas marketing
 
(25
)
 
(73
)
Fair value, net asset end of period
 
$
7,663

 
$
19,644

 
 
 
 
 
Changes in unrealized gains (losses) relating to assets (liabilities) still held
 
 
 
 
as of year-end, included in statement of operations line item:
 
 
 
 
Commodity price risk management gain, net
 
$
(2,739
)
 
$
1,282

Sales from natural gas marketing
 
(16
)
 
3

Total
 
$
(2,755
)
 
$
1,285

 
 
 
 
 
__________
(1)
Represents the change in fair value related to derivative instruments entered into by us and designated to our affiliated partnerships.

The significant unobservable input used in the fair value measurement of our derivative contracts is the implied volatility curve, which is provided by a third-party vendor. A significant increase or decrease in the implied volatility, in isolation, would have a directionally similar effect resulting in a significantly higher or lower fair value measurement of our Level 3 derivative contracts.
    
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.
 
The portion of our long-term debt related to our revolving credit facility, as well as our proportionate share of PDCM's credit facility, approximates fair value due to the variable nature of related interest rates. We have not elected to account for the portion of our long-term debt related to our senior notes under the fair value option; however, as of March 31, 2013, we estimate the fair value of the portion of our long-term debt related to the 3.25% convertible senior notes due 2016 to be $157.3 million, or 136.7% of par value, and the portion related to our 7.75% senior notes due 2022 to be $536.5 million, or 107.3% of par value. We determined these valuations based upon measurements of trading activity and broker and/or dealer quotes, respectively, which are published market prices, and therefore are Level 2 inputs.

NOTE 4 - DERIVATIVE FINANCIAL INSTRUMENTS

Our results of operations and operating cash flows are affected by changes in market prices for natural gas, NGLs and crude oil. To manage a portion of our exposure to price volatility from producing natural gas and crude oil, we utilize the following economic hedging strategies for each of our business segments.

For natural gas and crude oil sales, we enter into derivative contracts to protect against price declines in future periods. While we structure these derivatives to reduce our exposure to changes in price associated with the derivative commodity, they also limit the benefit we might otherwise have received from price increases in the physical market.
 
For natural gas marketing, we enter into fixed-price physical purchase and sale agreements that qualify as derivative contracts. In order to offset the fixed-price physical derivatives in our natural gas marketing, we enter into financial derivative instruments that have the effect of locking in the prices we will receive or pay for the same volumes and period, offsetting the physical derivative.

We believe our derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of March 31, 2013, we had derivative instruments, which were comprised of commodity floors, collars and swaps, basis protection swaps and physical sales and purchases, in place for a portion of our anticipated production through 2016 for a total of 72,674 BBtu of natural gas and 5,568 MBbls of crude oil.

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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued


We have elected not to designate any of our derivative instruments as hedges and therefore do not qualify for use of hedge accounting. Accordingly, changes in the fair value of our derivative instruments are recorded in the statements of operations, with the exception of changes in fair value related to those derivatives we designated to our affiliated partnerships. Changes in the fair value of derivative instruments related to our Oil and Gas Exploration and Production segment are recorded in commodity price risk management, net. Changes in the fair value of derivative instruments related to our Gas Marketing segment are recorded in sales from and cost of natural gas marketing. Changes in the fair value of the derivative instruments designated to our affiliated partnerships are recorded on the balance sheets in accounts payable affiliates and accounts receivable affiliates. As positions designated to our affiliated partnerships settle, the realized gains and losses are netted for distribution. Net realized gains are paid to the partnerships and net realized losses are deducted from the partnerships’ cash distributions from production. The affiliated partnerships bear their designated share of counterparty risk.

All of our derivative agreements contain master netting provisions that provide for the net settlement of all contracts through a single payment in the event of early termination. We have elected not to offset the fair value positions recorded on our condensed consolidated balance sheets. Pursuant to the master netting provisions contained in our derivative agreements, the fair value of our derivatives instruments was a net liability of $1.6 million as of March 31, 2013 and a net asset of $30.3 million as of December 31, 2012.

The following table presents the location and fair value amounts of our derivative instruments on the balance sheets as of March 31, 2013 and December 31, 2012:
 
 
 
 
 
Fair Value
Derivatives instruments:
 
Balance sheet line item
 
March 31, 2013
 
December 31, 2012
 
 
 
 
 
(in thousands)
Derivative assets:
Current
 
 
 
 
 
 
 
Commodity contracts
 
 
 
 
 
 
 
Related to natural gas and crude oil sales
 
Fair value of derivatives
 
$
25,526

 
$
47,016

 
Related to affiliated partnerships (1)
 
Fair value of derivatives
 
2,936

 
4,707

 
Related to natural gas marketing
 
Fair value of derivatives
 
877

 
302

 
Basis protection contracts
 
 
 
 
 
 
 
Related to natural gas and crude oil sales
 
Fair value of derivatives
 
493

 

 
Related to natural gas marketing
 
Fair value of derivatives
 
18

 
17

 
 
 
 
 
29,850

 
52,042

 
Non Current
 
 
 
 
 
 
 
Commodity contracts
 
 
 
 
 
 
 
Related to natural gas and crude oil sales
 
Fair value of derivatives
 
4,532

 
6,671

 
Related to natural gas marketing
 
Fair value of derivatives
 
321

 
203

 
Basis protection contracts
 
 
 
 
 
 
 
Related to natural gas and crude oil sales
 
Fair value of derivatives
 
325

 

 
Related to natural gas marketing
 
Fair value of derivatives
 
3

 
9

 
 
 
 
 
5,181

 
6,883

Total derivative assets
 
 
 
 
$
35,031

 
$
58,925

 
 
 
 
 
 
 
 
Derivative liabilities:
Current
 
 
 
 
 
 
 
Commodity contracts
 
 
 
 
 
 
 
Related to natural gas and crude oil sales
 
Fair value of derivatives
 
$
10,707

 
$
1,744

 
Related to natural gas marketing
 
Fair value of derivatives
 
730

 
226

 
Basis protection contracts
 
 
 
 
 
 
 
Related to natural gas and crude oil sales
 
Fair value of derivatives
 
10,552

 
14,329

 
Related to affiliated partnerships (2)
 
Fair value of derivatives
 
1,575

 
2,140

 
 
 
 
 
23,564

 
18,439

 
Non Current
 
 
 
 
 
 
 
Commodity contracts
 
 
 
 
 
 
 
Related to natural gas and crude oil sales
 
Fair value of derivatives
 
12,803

 
9,969

 
Related to natural gas marketing
 
Fair value of derivatives
 
243

 
168

 
 
 
 
 
13,046

 
10,137

Total derivative liabilities
 
 
 
 
$
36,610

 
$
28,576

__________
(1)
Represents derivative positions designated to our affiliated partnerships. Accordingly, our accompanying balance sheets include a corresponding payable to our affiliated partnerships representing their proportionate share of the derivative assets.
(2)
Represents derivative positions designated to our affiliated partnerships. Accordingly, our accompanying balance sheets include a corresponding receivable from our affiliated partnerships representing their proportionate share of the derivative liabilities.


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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

    
The following table presents the impact of our derivative instruments on our statements of operations:

 
 
Three Months Ended March 31,
 
 
2013
 
2012
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
 
 
(in thousands)
Commodity price risk management gain (loss), net
 
 
 
 
 
 
 
 
 
 
 
 
Realized gains
 
$
9,045

 
$
(571
)
 
$
8,474

 
$
8,628

 
$
1,299

 
$
9,927

Unrealized gains (losses)
 
(9,045
)
 
(21,784
)
 
(30,829
)
 
(8,628
)
 
10,202

 
1,574

Total commodity price risk management gain (loss), net
 
$

 
$
(22,355
)
 
$
(22,355
)
 
$

 
$
11,501

 
$
11,501

Sales from natural gas marketing
 
 
 
 
 
 
 
 
 
 
 
 
Realized gains
 
$
194

 
$
7

 
$
201

 
$
684

 
$
109

 
$
793

Unrealized gains (losses)
 
(194
)
 
(774
)
 
(968
)
 
(684
)
 
759

 
75

Total sales from natural gas marketing
 
$

 
$
(767
)
 
$
(767
)
 
$

 
$
868

 
$
868

Cost of natural gas marketing
 
 
 
 
 
 
 
 
 
 
 
 
Realized losses
 
$
(156
)
 
$
(6
)
 
$
(162
)
 
$
(591
)
 
$
(154
)
 
$
(745
)
Unrealized gains (losses)
 
156

 
920

 
1,076

 
591

 
(707
)
 
(116
)
Total cost of natural gas marketing
 
$

 
$
914

 
$
914

 
$

 
$
(861
)
 
$
(861
)
 
 
 
 
 
 
 
 
 
 
 
 
 

Derivative Counterparties. Our derivative arrangements expose us to credit risk of nonperformance by our counterparties. We primarily use financial institutions who are also lenders under our revolving credit facility as counterparties to our derivative contracts. To date, we have had no counterparty default losses. We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our counterparties on the fair value of our derivative instruments was not significant.

The following table presents the counterparties that expose us to credit risk as of March 31, 2013 with regard to our derivative assets:

Counterparty Name
 
Fair Value of
Derivative Assets
As of March 31, 2013
 
 
(in thousands)
 
 
 
JPMorgan Chase Bank, N.A. (1)
 
$
23,774

Bank of Nova Scotia (1)
 
2,237

Wells Fargo Bank, N.A. (1)
 
2,249

Other lenders in our revolving credit facility
 
5,479

Various (2)
 
1,292

Total
 
$
35,031

 
 
 
__________
(1)Major lender in our revolving credit facility. See Note 7, Long-Term Debt.
(2)Represents a total of 28 counterparties.


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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

NOTE 5 - PROPERTIES AND EQUIPMENT

The following table presents the components of properties and equipment, net of accumulated depreciation, depletion and amortization:

 
March 31, 2013
 
December 31, 2012
 
(in thousands)
Properties and equipment, net:
 
 
 
Natural gas and crude oil properties
 
 
 
Proved
$
1,399,879

 
$
2,075,924

Unproved
317,672

 
319,327

Total natural gas and crude oil properties
1,717,551

 
2,395,251

Pipelines and related facilities
14,995

 
47,786

Transportation and other equipment
27,518

 
34,858

Land and buildings
12,832

 
14,935

Construction in progress
55,325

 
67,217

Gross properties and equipment
1,828,221

 
2,560,047

Accumulated depreciation, depletion and amortization
(452,748
)
 
(943,341
)
Properties and equipment, net
$
1,375,473

 
$
1,616,706

 
 
 
 

The following table presents impairment charges recorded for natural gas and crude oil properties:

 
Three Months Ended
 
2013
 
2012
 
(in thousands)
Continuing operations:
 
 
 
Impairment of proved properties
$
45,000

 
$

Impairment of individually significant unproved properties
154

 
154

Amortization of individually insignificant unproved properties
1,305

 
434

Total continuing operations
46,459

 
588

Discontinued operations:
 
 
 
Amortization of individually insignificant unproved properties
3

 
65

Total discontinued operations
3

 
65

Total impairment of natural gas and crude oil properties
$
46,462

 
$
653

 
 
 
 

During the three months ended March 31, 2013, we recognized an impairment charge of approximately $45 million related to all of our shallow upper Devonian (non-Marcellus Shale) Appalachian Basin producing properties located in West Virginia and Pennsylvania owned directly by us, as well as through our proportionate share of PDCM and our affiliated partnerships. The assets were determined to be impaired when the assets became held for sale in the first quarter of 2013 as the estimated fair value, less cost to sell, was less than the carrying value of the assets. The fair value for determining the amount of the impairment charge was based upon estimated future cash flows from an unrelated third-party bid, a Level 3 input. The impairment charge was included in the statement of operations line item impairment of natural gas and crude oil properties. See Note 12, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information regarding these properties. It is not certain that these properties will be sold.

NOTE 6 - INCOME TAXES

We evaluate our estimated annual effective income tax rate on a quarterly basis based on current and forecasted operating results and tax laws. The estimated annual effective tax rate is adjusted quarterly based upon actual results and updated operating forecasts. Consequently, based upon the mix and timing of our actual earnings compared to annual projections, our effective tax rate may vary quarterly and may make quarterly comparisons not meaningful. A tax expense or benefit unrelated to the current year income or loss is recognized in its entirety as a discrete item of tax in the period identified. The quarterly income tax provision is generally comprised of tax expense on income or tax benefit on loss at the most recent estimated annual effective tax rate, adjusted for the effect of discrete items.

The effective tax rates for continuing operations for the three months ended March 31, 2013 was a 35.5% benefit on loss compared to a 37.9% expense on income for the three months ended March 31, 2012. The effective tax rates for the three month periods ended March 31, 2013 and March 31, 2012 approximate the federal statutory rate of 35.0%, plus our effective blended state tax rate of approximately 3.0%. For the three months ended March 31, 2012, our permanent deductions, largely percentage depletion, were offset by nondeductible items, primarily officers' compensation. For the three months ended March 31, 2013, the nondeductible item for officers' compensation exceeded our deduction

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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

for percentage depletion, thereby reducing our tax benefit rate. Additionally, state statutory limits on the utilization of our net operating losses resulted in a reduced state tax benefit. There were no significant discrete items recorded during the three months ended March 31, 2013 or 2012.

As of March 31, 2013, we had a gross liability for unrecognized tax benefits of $0.2 million, unchanged from the amount recorded at December 31, 2012. If recognized, this liability would affect our effective tax rate. This liability is reflected in other accrued expenses on our accompanying balance sheets. We expect our remaining liability for uncertain tax positions to decrease in the next twelve months due to the expiration of statute of limitations.

As of the date of this filing, we are current with our income tax filings in all applicable state jurisdictions and currently have no state income tax returns in the process of examination.

NOTE 7 - LONG-TERM DEBT

Long-term debt consists of the following:

 
March 31, 2013
 
December 31, 2012
 
(in thousands)
Senior notes:
 
 
 
3.25% Convertible senior notes due 2016:
 
 
 
Principal amount
$
115,000

 
$
115,000

Unamortized discount
(12,780
)
 
(13,671
)
3.25% Convertible senior notes due 2016, net of discount
102,220

 
101,329

7.75% Senior notes due 2022
500,000

 
500,000

Total senior notes
602,220

 
601,329

Credit facilities:
 
 
 
Corporate
57,000

 
49,000

PDCM
28,750

 
26,250

Total credit facilities
85,750

 
75,250

Total long-term debt
$
687,970

 
$
676,579


 
 
 
    
Senior Notes

3.25% Convertible Senior Notes Due 2016. In November 2010, we issued $115 million aggregate principal amount 3.25% convertible senior notes due May 15, 2016 (the "2016 Convertible Senior Notes") in a private placement to qualified institutional investors. Interest on the 2016 Convertible Senior Notes is payable semi-annually in arrears on each May 15 and November 15. We allocated the gross proceeds of the convertible senior notes between the liability and equity components of the debt. The initial $94.3 million liability component was determined based upon the fair value of similar debt instruments with similar terms, excluding the conversion feature, and priced on the same day we issued our convertible senior notes. The original issue discount and capitalized debt issuance costs are being amortized to interest expense over the life of the notes using an effective interest rate of 7.4%.

Upon conversion, the convertible senior notes may be settled, at our election, in shares of our common stock, cash or a combination of cash and shares of our common stock. We have initially elected a net-settlement method to satisfy our conversion obligation, which allows us to settle the principal amount of the convertible notes in cash and to settle the excess conversion value in shares, as well as cash in lieu of fractional shares.

7.75% Senior Notes Due 2022. In October 2012, we issued $500 million aggregate principal amount 7.75% senior notes due October 15, 2022 (the “2022 Senior Notes”) in a private placement to qualified institutional investors. Interest on the 2022 Senior Notes is payable semi-annually in arrears on each April 15 and October 15. The indenture governing the notes contains customary restrictive covenants. Capitalized debt issuance costs are being amortized as interest expense over the life of the notes using the effective interest method.

As of March 31, 2013, we were in compliance with all covenants related to the 2016 Convertible Senior Notes and the 2022 Senior Notes, and expect to remain in compliance throughout the next twelve-month period.
    
Credit Facilities

Revolving Credit Facility. In November 2010, we obtained a revolving credit facility pursuant to a Second Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A. as administrative agent and other lenders party thereto. The revolving credit facility is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes and to support letters of credit. The maximum facility amount is $600 million. As of March 31, 2013, the borrowing base on the revolving credit facility was $450 million and we had $57 million outstanding at a weighted-average interest rate of 2.72%, compared to $49 million at a weighted-average interest rate of 2.31%

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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

as of December 31, 2012. The borrowing base of the revolving credit facility is the loan value assigned to the proved reserves attributable to our and our subsidiaries' natural gas and crude oil interests, excluding proved reserves attributable to PDCM and our 21 affiliated partnerships. Our revolving credit facility borrowing base is subject to a semiannual size redetermination based on quantification of our reserves at June 30 and December 31, and is also subject to a redetermination upon the occurrence of certain events. The borrowing base redetermination based on our December 31, 2012 proved reserves is currently under review. The revolving credit facility is secured by a pledge of the stock of certain of our subsidiaries, mortgages of certain producing natural gas and crude oil properties and substantially all of our and such subsidiaries' other assets. Neither PDCM nor the various limited partnerships that we have sponsored, and continue to serve as the managing general partner, are guarantors of the revolving credit facility.

Our outstanding principal amount accrues interest at a varying interest rate that fluctuates with an alternate base rate (equal to the greater of JPMorgan Chase Bank, N.A.'s prime rate, the federal funds rate plus a premium and 1-month LIBOR plus a premium), or at our election, a rate equal to the rate for dollar deposits in the London interbank market for certain time periods. Additionally, commitment fees, interest margin and other bank fees, charged as a component of interest, vary with our utilization of the facility. No principal payments are required until the credit agreement expires on November 5, 2015, or in the event that the borrowing base would fall below the outstanding balance.

The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests and maintaining certain financial ratios on a quarterly basis. The financial tests and ratios, as defined per the revolving credit facility, include requirements to maintain a minimum current ratio of 1.00 to 1.00 and not exceed a maximum leverage ratio of 4.00 to 1.00.
  
As of March 31, 2013 we had an $18.7 million irrevocable standby letter of credit outstanding in favor of a third-party transportation service provider to secure firm transportation of the natural gas produced by us and others for whom we market production in West Virginia. The letter of credit reduces the amount of available funds under our revolving credit facility by an equal amount. We pay a fronting fee of 0.125% per annum and an additional quarterly maintenance fee equivalent to the spread over Eurodollar loans (2.0% per annum as of March 31, 2013) for the period in which the letter of credit remains outstanding. The letter of credit expires on July 20, 2013. We expect to renew the letter of credit prior to its expiration.

We pay a fee of 0.5% per annum on the unutilized commitment on the available funds under our revolving credit facility. As of March 31, 2013, the available funds under our revolving credit facility, including a reduction for the $18.7 million irrevocable standby letter of credit in effect, was $374.3 million.

PDCM Credit Facility. PDCM has a credit facility dated April 30, 2010, as amended, with an aggregate revolving commitment or borrowing base of $80 million, of which our proportionate share is $40 million. The maximum allowable facility amount is $400 million. At PDCM's discretion, interest accrues at either an alternative base rate ("ABR") or an adjusted LIBOR. The ABR is the greater of Wells Fargo's prime rate, the federal funds effective rate plus 0.5% or the adjusted LIBOR for a three month interest period plus 1%. ABR and adjusted LIBOR borrowings are assessed an additional margin based upon the outstanding balance as a percentage of the available balance. ABR borrowings are assessed an additional margin of 1.25% to 2.0%. Adjusted LIBOR borrowings are assessed an additional margin spread of 2.25% to 3.0%. No principal payments are required until the credit agreement expires on April 30, 2014, or in the event that the borrowing base falls below the outstanding balance. The credit facility is subject to and secured by PDCM's properties, including our proportionate share of such properties. The credit facility borrowing base is subject to size redetermination semiannually based upon a valuation of PDCM's reserves at June 30 and December 31. Either PDCM or the lenders may request a redetermination upon the occurrence of certain events. The borrowing base redetermination based on our December 31, 2012 proved reserves is currently under review. Pursuant to the interests of the joint venture, the credit facility will be utilized by PDCM for the exploration and development of its Marcellus assets.

The credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests and financial ratios that must be met on a quarterly basis. The financial tests and ratios, as defined by the credit facility, include requirements to maintain a minimum current ratio of 1.0 to 1.0, not to exceed a debt to EBITDAX ratio of 4.5 to 1.0 (declining to 4.0 to 1.0 on September 30, 2013) and to maintain a minimum interest coverage ratio of 2.5 to 1.0. As of March 31, 2013, our proportionate share of PDCM's outstanding credit facility balance was $28.8 million compared to $26.3 million as of December 31, 2012. PDCM is required to pay a commitment fee of 0.5% per annum on the unutilized portion of the activated credit facility. The weighted-average borrowing rate on PDCM's credit facility was 3.6% per annum as of March 31, 2013, compared to 3.5% as of December 31, 2012.

As of March 31, 2013, we were in compliance with all credit facility covenants and expect to remain in compliance throughout the next twelve-month period.


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Table of contents
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

NOTE 8 - ASSET RETIREMENT OBLIGATIONS

The following table presents the changes in carrying amounts of the asset retirement obligations associated with our working interest in natural gas and crude oil properties:
 
Amount
 
(in thousands)
 
 
Balance at December 31, 2012
$
62,563

Obligations incurred with development activities
98

Accretion expense
1,245

Obligations discharged with disposal of properties and asset retirements
(264
)
Balance at March 31, 2013
63,642

Liabilities held for sale (1)
(28,346
)
Less current portion
(1,000
)
Long-term portion
$
34,296

 
 
______________
(1)
Represents asset retirement obligations related to our assets held for sale. See Note 12, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information regarding the planned sale of these properties.

NOTE 9 - COMMITMENTS AND CONTINGENCIES

Firm Transportation Agreements. We enter into contracts that provide firm transportation, sales and processing services on pipeline systems through which we transport or sell natural gas. Satisfaction of the volume requirements includes volumes produced by us, purchased from third parties and produced by PDCM, our affiliated partnerships and other third-party working interest owners. We record in our financial statements only our share of costs based upon our working interest in the wells. These contracts require us to pay these transportation and processing charges whether the required volumes are delivered or not. With the exception of contracts entered into by PDCM, the costs of any volume shortfalls are borne by PDC.
        
The following table presents gross volume information, including our proportionate share of PDCM, related to our long-term firm transportation, sales and processing agreements for pipeline capacity:
 
 
For the Twelve Months Ending March 31,
 
 
 
 
Area
 
2014
 
2015
 
2016
 
2017
 
2018 and
Through
Expiration
 
Total
 
Expiration
Date
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Volume (MMcf)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Piceance Basin
 
32,114

 
15,522

 
10,277

 
9,319

 
31,653

 
98,885

 
May 31, 2021
Appalachian Basin
 
20,238

 
25,028

 
23,923

 
24,795

 
162,165

 
256,149

 
September 20, 2025
NECO
 
2,100

 
1,825

 
1,830

 
1,375

 

 
7,130

 
December 31, 2016
Utica Shale
 
1,541

 
2,623

 
2,738

 
2,738

 
17,115

 
26,755

 
June 30, 2023
Total
 
55,993

 
44,998

 
38,768

 
38,227

 
210,933

 
388,919

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Dollar commitment
(in thousands)
 
$
26,998

 
$
19,529

 
$
16,612

 
$
16,026

 
$
69,428

 
$
148,593

 
 

Effective January 1, 2013, we entered into a new gas gathering and processing agreement with Williams Field Services Company related to our Piceance Basin production. The new agreement included additional terms and conditions which, among other things, reduced our Piceance Basin total committed volumes for gathering over the term of the agreement. In February 2013, we entered into a purchase and sale agreement pursuant to which our Piceance Basin and NECO firm transportation and processing commitments will be assumed by the purchaser of certain of our oil and natural gas properties upon the closing of the transaction. See Note 12, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information regarding the planned sale. There can be no assurance that we will be successful in closing such divestiture.

In March 2013, we entered into long-term agreements with a subsidiary of MarkWest Energy Partners, LP to provide midstream services, including gas gathering, processing, fractionation and marketing, to support our Utica Shale operations in Guernsey County in Southeast Ohio. The primary term of the agreements is ten years commencing when our natural gas begins to flow into the gathering system. The gas processing agreement includes minimum volume commitments as shown in the table above, with certain fees assessed for any shortfall.

Litigation. The Company is involved in various legal proceedings that it considers normal to its business. The Company reviews the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in the best interests of the Company. There is no assurance that settlements can be reached on acceptable terms or that adverse judgments, if any, in the remaining litigation will not exceed the amounts reserved. Although the results cannot be known with

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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

certainty, we currently believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations or liquidity.

Alleged Class Action Filed Regarding 2010 and 2011 Partnership Purchases

On December 21, 2011 the Company and its wholly-owned merger subsidiary were served with an alleged class action on behalf of certain former partnership unit holders, related to its partnership repurchases completed by mergers in 2010 and 2011. The action was filed in U.S. District Court for the Central District of California and is titled Schulein v. Petroleum Development Corp. The complaint primarily alleges that the disclosures in the proxy statements issued in connection with the mergers were inadequate, and a state law breach of fiduciary duty. On February 10, 2012, the Company filed a motion to dismiss or in the alternative to stay. On June 15, 2012, the Court denied the motion. The Court has approved a litigation schedule including a jury trial in May 2014. We have not recorded a liability for claims pending because we believe we have good legal defenses to the asserted claims and because the plaintiffs have not specified damages and it is not possible for management to reasonably estimate what, if any, monetary damages could result from this claim.

Environmental. Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures to avoid environmental contamination and mitigate the risks from environmental contamination. We conduct periodic reviews to identify changes in our environmental risk profile. Liabilities are recorded when environmental damages resulting from past events are probable and the costs can be reasonably estimated. As of March 31, 2013 and December 31, 2012, we had accrued environmental liabilities in the amount of $6.3 million and $8.4 million, respectively, included in other accrued expenses on the balance sheets. We are not aware of any environmental claims existing as of March 31, 2013 which have not been provided for or would otherwise have a material impact on our 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 our properties.

Partnership Repurchase Provision. Substantially all of our drilling programs contain a repurchase provision where investing partners may request that we purchase their partnership units at any time beginning with the third anniversary of the first cash distribution. The provision provides that we are obligated to purchase an aggregate of 10% of the initial subscriptions per calendar year (at a minimum price of four times the most recent 12 months' cash distributions from production), if repurchase is requested by investors, subject to our financial ability to do so. As of March 31, 2013, the maximum annual repurchase obligation, based upon the minimum price described above, was approximately $3.9 million. We believe we have adequate liquidity to meet this potential obligation. For the quarter ended March 31, 2013, amounts paid for the repurchase of partnership units pursuant to this provision were immaterial.
    
Employment Agreements with Executive Officers. Each of our senior executive officers may be entitled to a severance payment and certain other benefits upon the termination of the officer's employment pursuant to the officer's employment agreement and/or the Company's executive severance compensation plan. The nature and amount of such benefits would vary based upon, among other things, whether the termination followed a change of control of the Company.

NOTE 10 - COMMON STOCK

Stock-Based Compensation Plans

The following table provides a summary of the impact of our outstanding stock-based compensation plans on the results of operations for the periods presented:

 
 
Three Months Ended March 31,
 
 
2013
 
2012 (1)
 
 
(in thousands)
 
 
 
 
 
Stock-based compensation expense
 
$
2,602

 
$
1,946

Income tax benefit
 
(994
)
 
(741
)
Net expense
 
$
1,608

 
$
1,205

 
 
 
 
 

Stock Appreciation Rights ("SARs")

The SARs vest ratably over a three-year period and may be exercised at any point after vesting through 10 years from the date of issuance. Pursuant to the terms of the awards, upon exercise, the executive officers will receive, in shares of common stock, the excess of the market price of the award on the date of exercise over the market price of the award on the date of issuance.


13

Table of contents
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

In January 2013, the Compensation Committee awarded 87,078 SARs to our executive officers. The fair value of each SAR award was estimated on the date of grant using a Black-Scholes pricing model using the following assumptions:

 
Three Months Ended March 31,
 
2013
 
2012
 
 
 
 
Expected term of award
6 years

 
6 years

Risk-free interest rate
1.0
%
 
1.1
%
Expected volatility
65.5
%
 
64.3
%
Weighted-average grant date fair value per share
$
21.96

 
$
17.61


The expected life of the award was estimated using historical stock option exercise behavior data. The risk-free interest rate was based on the U.S. Treasury yields approximating the expected life of the award in effect at the time of grant. Expected volatilities were based on our historical volatility. We do not expect to pay or declare dividends in the foreseeable future.
    
The following table presents the changes in our SARs:

 
Three Months Ended March 31,
 
2013
 
2012
 
Number of
SARs
 
Weighted-Average
Exercise
Price
 
Average Remaining Contractual
Term
(in years)
 
Aggregate Intrinsic
Value
(in thousands)
 
Number of
SARs
 
Weighted-Average
Exercise
Price
 
Average Remaining Contractual
Term
(in years)
 
Aggregate Intrinsic
Value
(in thousands)
Outstanding beginning of year, January 1,
118,832

 
$
30.80

 
8.4

 
$
486

 
50,471

 
$
31.61

 
8.6

 
$
341

Awarded
87,078

 
37.18

 

 

 
68,361

 
30.19

 

 

Outstanding at March 31,
205,910

 
33.50

 
8.9

 
3,310

 
118,832

 
30.80

 
9.2

 
875

Vested and expected to vest at March 31,
194,689

 
33.38

 
8.8

 
3,152

 
111,137

 
30.76

 
9.2

 
825

Exercisable at March 31,
56,430

 
31.04

 
8.0

 
1,046

 
16,822

 
31.61

 
8.4

 
135


Total compensation cost related to SARs granted, net of estimated forfeitures, and not yet recognized in our statement of operations as of March 31, 2013 was $2.5 million. The cost is expected to be recognized over a weighted-average period of 2.4 years.
    
Restricted Stock Awards

Time-Based Awards. The fair value of the time-based restricted shares is amortized ratably over the requisite service period, primarily three or four years. The time-based shares vest ratably on each annual anniversary following the grant date that a participant is continuously employed.

In January 2013, the Compensation Committee awarded a total of 103,050 time-based restricted shares to our executive officers that vest ratably over three year period ending on January 16, 2016.

The following table presents the changes in non-vested time-based awards for the three months ended March 31, 2013:
 
Shares
 
Weighted-Average
Grant-Date
Fair Value
 
 
 
 
Non-vested at December 31, 2012
646,490

 
$
27.93

Granted
118,518

 
36.82

Vested
(55,918
)
 
29.85

Forfeited
(11,648
)
 
26.48

Non-vested at March 31, 2013
697,442

 
29.31

 
 
 
 


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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

 
As of/Three Months Ended March 31,
 
2013
 
2012
 
(in thousands, except per share data)
 
 
 
 
Total intrinsic value of time-based awards vested
$
2,303

 
$
1,104

Total intrinsic value of time-based awards non-vested
34,572

 
21,918

Market price per common share as of March 31,
49.57

 
37.09

Weighted-average grant date fair value per share
36.82

 
31.23


Total compensation cost related to non-vested time-based awards, net of estimated forfeitures, and not yet recognized in our statements of operations as of March 31, 2013 was $13.3 million. This cost is expected to be recognized over a weighted-average period of 2.3 years.

Market-Based Awards. The fair value of the market-based restricted shares is amortized ratably over the requisite service period, primarily three years. The market-based shares vest if the participant is continuously employed throughout the performance period and the market-based performance measure is achieved, with a maximum vesting period of between three to five years. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved.
In January 2013, the Compensation Committee awarded a total of 41,570 market-based restricted shares to our executive officers. In addition to continuous employment, the vesting of these shares is contingent on the Company's total shareholder return ("TSR"), which is essentially the Company’s stock price change including any dividends, as compared to the TSR of a set group of 16 peer companies. The shares are measured over a three-year period ending on December 31, 2015 and can result in a payout between 0% and 200% of the total shares awarded. The weighted-average grant date fair value per market-based share for these awards granted was computed using the Monte Carlo pricing model using the following assumptions:
 
 
Three Months Ended March 31,
 
 
2013
 
2012
 
 
 
 
 
Expected term of award
 
3 years

 
3 years

Risk-free interest rate
 
0.4
%
 
0.3
%
Expected volatility
 
56.6
%
 
65.3
%
Weighted-average grant date fair value per share
 
$
49.04

 
$
36.54


The expected term of the awards was based on the requisite service period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant and extrapolated to approximate the life of the award. The expected volatility was based on our historical volatility. We do not expect to pay or declare dividends in the foreseeable future.
    
The following table presents the change in non-vested market-based awards during three months ended March 31, 2013:
 
 
Shares
 
Weighted-Average
Grant-Date
Fair Value per Share
 
 
 
 
 
Non-vested at December 31, 2012
 
40,696

 
$
39.22

Granted
 
41,570

 
49.04

Non-vested at March 31, 2013
 
82,266

 
44.18

 
 
 
 
 

 
As of/Year Ended March 31,
 
2013
 
2012
 
(in thousands, except per share data)
 
 
 
 
Total intrinsic value of market-based awards non-vested
$
4,078

 
$
2,731

Market price per common share as of March 31,
49.57

 
37.09

Weighted-average grant date fair value per share
49.04

 
36.54


Total compensation cost related to non-vested market-based awards, net of estimated forfeitures, and not yet recognized in our statement of operations as of March 31, 2013 was $2.5 million. This cost is expected to be recognized over a weighted-average period of 2.4 years.


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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

NOTE 11 - EARNINGS PER SHARE

Basic earnings per share is computed by dividing net income (loss) by the weighted-average number of common shares outstanding for the period. Diluted earnings per share is similarly computed except that the denominator includes the effect, using the treasury stock method, of unvested restricted stock, outstanding SARs, stock options, convertible senior notes and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive.

The following table presents a reconciliation of the weighted-average diluted shares outstanding:

 
Three Months Ended March 31,
 
2013
 
2012
 
(in thousands)
 
 
 
 
Weighted-average common shares outstanding - basic
30,270

 
23,609

Dilutive effect of:
 
 
 
Restricted stock

 
212

SARs

 
65

Non-employee director deferred compensation

 
3

Weighted-average common and common share equivalents outstanding - diluted
30,270

 
23,889

 
 
 
 

The following table presents the weighted-average common share equivalents excluded from the calculation of diluted earnings per share due to their anti-dilutive effect:

 
Three Months Ended March 31,
 
2013
 
2012
 
(in thousands)
 
 
 
 
Weighted-average common share equivalents excluded from diluted earnings
 
 
 
per share due to their anti-dilutive effect:
 
 
 
Restricted stock
844

 
27

SARs
45

 
19

Stock options
3

 
7

Non-employee director deferred compensation
4

 

Convertible senior notes
48

 

Total anti-dilutive common share equivalents
944

 
53

 
 
 
 

We reported a net loss for the three months ended March 31, 2013. As a result, our basic and diluted weighted-average common shares outstanding were the same as the effect of the common share equivalents was anti-dilutive.

In November 2010, we issued 115,000 convertible senior notes, $1,000 principal amount per note, that give the holders the right to convert the aggregate principal amount into 2.7 million common shares at a conversion price of $42.40 per share. These convertible senior notes could be included in the dilutive earnings per share calculation using the treasury stock method if the average market share price exceeds the $42.40 conversion price during the period presented. Shares issuable under the convertible senior notes were excluded from the diluted earnings per share calculation for the three month ended March 31, 2013 as the effect would be anti-dilutive to our earnings. Shares issuable under the convertible senior notes were excluded from the diluted earnings per share calculation for the three months ended March 31, 2012 as the conversion price was greater than the average market price of our common stock during the period.

NOTE 12 - ASSETS HELD FOR SALE, DIVESTITURES AND DISCONTINUED OPERATIONS
    
Piceance Basin and NECO. On February 4, 2013, we entered into a purchase and sale agreement with certain affiliates of Caerus Oil and Gas LLC (“Caerus”), pursuant to which we have agreed to sell to Caerus our Piceance Basin, NECO and certain other non-core Colorado oil and gas properties, leasehold mineral interests and related assets for aggregate cash consideration of approximately $190 million, subject to post-closing adjustments. These assets have been classified as held for sale in the condensed consolidated balance sheet as of March 31, 2013. The cash consideration is subject to customary adjustments, including adjustments based upon title and environmental due diligence, and by certain firm transportation obligations and natural gas hedging positions that will be assumed by Caerus. The proceeds from the asset disposal will be used to pay down our revolving credit facility and to fund a portion of our 2013 capital budget. There can be no assurance we will be successful in closing such divestiture. Following the planned sale, we will not have significant continuing involvement in the operations of, or cash flows from, the Piceance Basin and NECO oil and gas properties. Accordingly, the results of operations related to these assets have been

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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

separately reported as discontinued operations in the condensed consolidated statement of operations for all periods presented. The planned sale of our other non-core Colorado oil and gas properties do not meet the requirements to be accounted for as discontinued operations.

Appalachian Basin. During the three months ended March 31, 2013, we developed a plan to market all of our shallow upper Devonian (non-Marcellus Shale) Appalachian Basin crude oil and natural gas properties located in West Virginia and Pennsylvania owned directly by us, as well as through our proportionate share of PDCM and our affiliated partnerships. The properties being marketed consist of approximately 3,500 gross shallow producing wells, related facilities and associated shallow leasehold acreage, limited to the upper Devonian and shallower formations. The company is retaining all zones, formations and intervals below the upper Devonian formation including the Marcellus Shale, Utica Shale and Huron Shale. Any proceeds from the sale of these shallow upper Devonian assets will be used to fund a portion of our Marcellus drilling program in the Appalachian Basin. It is not certain that these properties will be sold. We have classified the related assets owned directly by us, as well as through our proportionate share of PDCM and our affiliated partnerships, as held for sale in the condensed consolidated balance sheet as of March 31, 2013. The planned divestiture of these assets does not meet the requirements to be accounted for as discontinued operations.

Permian Basin. In December 2011, we executed a purchase and sale agreement with COG Operating LLC (“COG”), a wholly owned subsidiary of Concho Resources Inc., an unrelated third-party, for the sale of our core Permian Basin assets for a sale price of $173.9 million, subject to customary terms and adjustments, including adjustments based on title and environmental due diligence to be conducted by COG. The effective date of the transaction was November 1, 2011. Following the sale to COG, we do not have significant continuing involvement in the operations of, or cash flows from, these assets. Accordingly, the results of operations related to the Permian assets have been separately reported as discontinued operations in the condensed consolidated statement of operations for the three months ended March 31, 2012. In February 2012, the divestiture closed. Upon final settlement, total proceeds received were $189.2 million after closing adjustments.

Selected financial information related to divested and discontinued operations. The tables below set forth selected financial information related to net assets held for sale and operating results related to discontinued operations. Net assets held for sale represents the assets that are expected to be sold, net of liabilities that are expected to be assumed by the purchaser. 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.

The following table presents balance sheet data related to assets held for sale as of March 31, 2013:

Balance Sheet
 
Net Assets Held for Sale
 
 
(in thousands)
Assets
 
 
Properties and equipment
 
$
782,556

Accumulated depreciation, depletion and amortization
 
(565,754
)
Total Assets
 
$
216,802

 
 
 
Liabilities
 
 
Asset retirement obligation
 
$
28,346

 
 
 
Net Assets
 
$
188,456

 
 
 
    

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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

The following table presents statement of operations data related to our discontinued operations:

 
 
Three Months Ended
Statements of Operations - Discontinued Operations
 
2013
 
2012
 
 
(in thousands)
Revenues
 
 
 
 
Natural gas, NGLs and crude oil sales
 
$
10,274

 
$
12,811

Sales from natural gas marketing
 
450

 
453

Well operations, pipeline income and other
 
450

 
566

Total revenues
 
11,174

 
13,830

 
 
 
 
 
Costs, expenses and other
 
 
 
 
Production costs
 
5,393

 
7,102

Cost of natural gas marketing
 
454

 
401

Depreciation, depletion and amortization
 
2,258

 
11,902

Other
 
495

 
348

Gain on sale of properties and equipment
 

 
(20,335
)
Total costs, expenses and other
 
8,600

 
(582
)
 
 
 
 
 
Income from discontinued operations
 
2,574

 
14,412

Provision for income taxes
 
(1,037
)
 
(5,341
)
Income from discontinued operations, net of tax
 
$
1,537

 
$
9,071

 
 
 
 
 

NOTE 13 - TRANSACTIONS WITH AFFILIATES AND OTHER RELATED PARTIES

PDCM and Affiliated Partnerships. Our Gas Marketing segment markets the natural gas produced by PDCM and our affiliated partnerships in the eastern operating region.

Amounts due from/to the affiliated partnerships are primarily related to derivative positions and, to a lesser extent, unbilled well lease operating expenses, and costs resulting from audit and tax preparation services. We have entered into derivative instruments on behalf of our affiliated partnerships for their estimated production.

The following table presents amounts included in our condensed consolidated statements of operations related to the marketing of natural gas on behalf of PDCM and our affiliated partnerships and amounts included in our condensed consolidated balance sheets related to the derivative instruments we entered into on behalf of our affiliated partnerships:

 
 
Three Months Ended March 31,
Statement of Operations
 
2013
 
2012
 
 
(in thousands)
PDCM:
 
 
 
 
Sales from natural gas marketing
 
$
3,725

 
$
2,442

Cost of natural gas marketing
 
3,652

 
2,394

Affiliated Partnerships:
 
 
 
 
Sales from natural gas marketing
 
268

 
119

Cost of natural gas marketing
 
274

 
116


 
 
As of
Balance Sheet
 
March 31, 2013
 
December 31, 2012
 
 
(in thousands)
Affiliated Partnerships:
 
 
 
 
Receivable from affiliated partnerships
 
$
1,575

 
$
2,140

Payable to affiliated partnerships
 
2,936

 
4,707



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PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

We provide certain well operating and administrative services for PDCM. Amounts billed to PDCM for these services were $3.4 million and $3.2 million for the quarters ended March 31, 2013 and 2012, respectively. Our statements of operations include only our proportionate share of these billings. The following table presents the statement of operations line item in which our proportionate share is recorded and the amount for each of the periods presented.
 
 
Three Months Ended March 31,
Statement of Operations Line Item
 
2013
 
2012
 
 
(in thousands)
 
 
 
 
 
Production costs
 
$
1,066

 
$
1,056

Exploration expense
 
105

 
132

General and administrative expense
 
515

 
414

 
NOTE 14 - BUSINESS SEGMENTS

We separate our operating activities into two segments: (1) Oil and Gas Exploration and Production and (2) Gas Marketing. All material inter-company accounts and transactions between segments have been eliminated.

Oil and Gas Exploration and Production. Our Oil and Gas Exploration and Production segment includes all of our natural gas and crude oil properties. The segment represents revenues and expenses from the production and sale of natural gas, NGLs and crude oil. Segment revenue includes natural gas, NGLs and crude oil sales, commodity price risk management, net and well operation and pipeline income. Segment income (loss) consists of segment revenue less production cost, exploration expense, impairment of natural gas and crude oil properties, direct general and administrative expense and depreciation, depletion and amortization expense.

Gas Marketing. Our Gas Marketing segment purchases, aggregates and resells natural gas produced by us and others. Segment income (loss) primarily represents sales from natural gas marketing and direct interest income, less costs of natural gas marketing and direct general and administrative expense.

Unallocated amounts. Unallocated income includes corporate general administrative expense, corporate depreciation, depletion and amortization expense, interest income and interest expense.
    
The following tables present our segment information:

 
Three Months Ended March 31,
 
2013
 
2012
 
(in thousands)
Revenues:
 
 
 
Oil and gas exploration and production
$
58,156

 
$
79,625

Gas marketing
13,670

 
11,381

Total revenues
$
71,826

 
$
91,006

 
 
 
 
Segment income (loss) before income taxes:
 
 
 
Oil and gas exploration and production
$
(33,702
)
 
$
37,424

Gas marketing
(66
)
 
290

Unallocated
(29,679
)
 
(26,830
)
Total
$
(63,447
)
 
$
10,884

 
 
 
 

 
March 31, 2013
 
December 31, 2012
 
(in thousands)
Segment assets:
 
 
 
Oil and gas exploration and production
$
1,460,815

 
$
1,723,011

Gas marketing
10,204

 
11,090

Unallocated
93,992

 
92,747

Assets held for sale
216,802

 

Total Assets
$
1,781,813

 
$
1,826,848

 
 
 
 


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Table of contents
PDC ENERGY, INC.


ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis, as well as other sections in this report, should be read in conjunction with our condensed consolidated financial statements and related notes included elsewhere in this report. Further, we encourage you to revisit the Special Note Regarding Forward-Looking Statements.

EXECUTIVE SUMMARY

Financial Overview

We recorded strong increases in natural gas, NGLs and crude oil sales from continuing operations during the three months ended March 31, 2013 as a direct result of our significant increase in production. Total natural gas, NGLs and crude oil sales increased $12.4 million, or 18.6%, to $79.4 million during the three months ended March 31, 2013 compared to $67 million during the three months ended March 31, 2012. Our natural gas, NGLs and crude oil production from continuing operations during the three months ended March 31, 2013 averaged 18.5 Mboe per day, an increase of approximately 18.6% compared to the three months ended March 31, 2012. The increase in production is primarily attributable to our successful horizontal Niobrara and Codell drilling program in the Wattenberg Field and to a lesser extent certain Wattenberg assets acquired in June 2012. Crude oil production from continuing operations increased 22.8% during the three months ended March 31, 2013, while NGL production from continuing operations increased 4.9%. Our liquids percentage of total production from continuing operations was 54.4% during the three months ended March 31, 2013. Natural gas production increased 17.1% during the three months ended March 31, 2013 compared to the same period in 2012.

Available liquidity as of March 31, 2013 was $388.1 million, including $12.4 million through our joint venture PDCM, compared to $398.6 million, including $14.1 million related to PDCM, as of December 31, 2012. Available liquidity is comprised of cash, cash equivalents and funds available under revolving credit facilities. We believe we have sufficient liquidity to allow us to execute our drilling program in the Wattenberg Field and the Utica Shale.
 
Operational Overview

Drilling Activities. During the three months ended March 31, 2013, we continued to focus our operations primarily in the oil- and liquid-rich Wattenberg Field in Colorado and the emerging Utica Shale play in Ohio. In our western operating region, we currently have two drilling rigs operating in the Wattenberg Field. We spud 11 horizontal wells in the Wattenberg Field, four of which were completed, during the three months ended March 31, 2013 and participated in ten gross, two net, horizontal non-operated drilling projects. We also executed six refracture and/or recompletion projects on three wells in the Wattenberg Field.

In our eastern operating region, we spud two horizontal Utica wells during the quarter on our first three-well pad, all of which were in-process as of March 31, 2013. These wells are expected to be turned-in-line during the third quarter of 2013. Of the wells drilled in 2012, one well remains shut-in awaiting pipeline connections, while production volumes from the second well are being sold through a temporary arrangement pending connection to permanent facilities. In addition, PDCM spud four horizontal Marcellus wells during the three months ended March 31, 2013, all of which were in-process as of March 31, 2013.

Planned Natural Gas and Crude Oil Properties Divestitures. On February 4, 2013, we entered into a purchase and sale agreement with certain affiliates of Caerus Oil and Gas LLC (“Caerus”), pursuant to which we have agreed to sell to Caerus our Piceance Basin, NECO and certain other non-core Colorado oil and gas properties, leasehold mineral interests and related assets for aggregate cash consideration of approximately $190 million. The cash consideration is subject to customary adjustments, including adjustments based upon title and environmental due diligence, and adjustments relating to certain firm transportation obligations and natural gas hedging positions that will be assumed by Caerus. We intend to use the proceeds from the sale to repay amounts outstanding under our revolving credit facility and partially fund our 2013 capital program. As of December 31, 2012, total estimated proved reserves related to these assets were 83,656 MMcf of natural gas and 148 MBbls of crude oil, for an aggregate of 14,091 MBbls of crude oil equivalent. See Note 12, Assets Held for Sale, Divestitures and Discontinued Operations, to our condensed consolidated financial statements included elsewhere in this report for additional details related to the planned divestiture of our Piceance and NECO assets. There can be no assurance that this transaction will close as planned. In addition, purchase price adjustments may reduce our proceeds from the transaction.

Non-U.S. GAAP Financial Measures

We use "adjusted cash flows from operations," "adjusted net income (loss)" and "adjusted EBITDA," non-U.S. GAAP financial measures, for internal management reporting, when evaluating period-to-period changes and providing public guidance on possible future results. These measures are not measures of financial performance under U.S. GAAP and should be considered in addition to, not as a substitute for, net income (loss) or cash flows from operations, investing or financing activities, and should not be viewed as a liquidity measure or indicator of cash flows reported in accordance with U.S. GAAP. The non-U.S. GAAP financial measures that we use may not be comparable to similarly titled measures reported by other companies. Also, in the future, we may disclose different non-U.S. GAAP financial measures in order to help our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We strongly encourage investors to review our financial statements and publicly filed reports in their entirety and to not rely on any single financial measure. See Reconciliation of Non-U.S. GAAP Financial Measures for a detailed description of these measures, as well as a reconciliation of each to the most comparable U.S. GAAP measure.

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Table of contents
PDC ENERGY, INC.

Results of Operations

Summary Operating Results

The following table presents selected information regarding our operating results from continuing operations:
 
Three Months Ended March 31,
 
 
 
 
 
 
 
2013
 
2012
 
Percentage Change
 
(dollars in millions, except per unit data)
Production (1)
 
 
 
 
 
Natural gas (MMcf)
4,549.8

 
3,884.5

 
17.1
 %
Crude oil (MBbls)
668.3

 
544.4

 
22.8
 %
NGLs (MBbls)
238.3

 
227.2

 
4.9
 %
Crude oil equivalent (MBoe) (2)
1,665.0

 
1,419.0

 
17.3
 %
Average MBoe per day
18.5

 
15.6

 
18.6
 %
Natural Gas, NGLs and Crude Oil Sales
 
 
 
 
 
Natural gas
$
14.0

 
$
10.0

 
40.1
 %
Crude oil
58.1

 
50.6

 
15.0
 %
NGLs
7.3

 
6.4

 
14.1
 %
Total natural gas, NGLs and crude oil sales
$
79.4

 
$
67.0

 
18.6
 %
 
 
 
 
 
 
Realized Gain (Losses) on Derivatives, net (3)
 
 
 
 
 
Natural gas
$
8.0

 
$
12.5

 
(36.1
)%
Crude oil
0.5

 
(2.6
)
 
*

Total realized gain on derivatives, net
$
8.5

 
$
9.9

 
(14.6
)%
 
 
 
 
 
 
Average Sales Price (excluding gain (loss) on derivatives)
 
 
 
 
 
Natural gas (per Mcf)
$
3.09

 
$
2.58

 
19.8
 %
Crude oil (per Bbl)
86.96

 
92.86

 
(6.4
)%
NGLs (per Bbl)
30.48

 
28.01

 
8.8
 %
Crude oil equivalent (per Boe)
47.71

 
47.18

 
1.1
 %
 
 
 
 
 
 
Average Sales Price (including realized gain (loss) on derivatives)
 
 
 
 
 
Natural gas (per Mcf)
$
4.85

 
$
5.81

 
(16.5
)%
Crude oil (per Bbl)
87.67

</