News Column

Penn Virginia Corporation Announces First Quarter 2014 Results

May 12, 2014

First Quarter Adjusted EBITDAX of $94 Million on Record Oil Production

Strong Results From Second Upper Eagle Ford Test Well

Eagle Ford Net Acreage Increased to Approximately 86,000 Acres

Drilling Inventory Increased Significantly to Approximately 1,510 Locations

RADNOR, Pa., May 12, 2014 (GLOBE NEWSWIRE) -- Penn Virginia Corporation (NYSE:PVA) today reported financial results for the three months ended March 31, 2014 and provided updates of its operations and 2014 guidance.

First Quarter 2014 Results and Highlights

First quarter 2014 financial results, with applicable comparisons to fourth quarter 2013 results, and highlights were as follows:

• Product revenues from the sale of oil, natural gas liquids (NGLs) and natural gas were $133.2 million, or $70.01 per barrel of oil equivalent (BOE), compared to $117.1 million, or $63.58 per BOE.• Oil and NGL revenues were $114.9 million, or 86 percent of product revenues, compared to $105.0 million, or 90 percent of product revenues.• Cash margin per BOE, a non-GAAP (generally accepted accounting principles) measure, excluding share-based compensation expenses, was $53.93 per BOE, compared to $48.48 per BOE.• Adjusted EBITDAX, a non-GAAP measure, was $93.8 million, compared to $84.4 million.• Operating income was $14.9 million, excluding $57.4 million of gain on the sale of assets, compared to operating income of $15.5 million.• Net income attributable to common shareholders (which includes our preferred stock dividend) was $17.5 million, or $0.22 per diluted share, compared to a net loss of $4.1 million, or $0.06 per diluted share.• Adjusted net loss attributable to common shareholders, a non-GAAP measure which includes our preferred stock dividend but excludes the effects of items that affect comparability to other periods, was $7.9 million, or $0.12 per diluted share, compared to a loss of $6.7 million, or $0.10 per diluted share.• In January 2014, we sold our Eagle Ford Shale natural gas gathering assets for a price of $100 million, $96 million net to our working interest. • In May 2014, the borrowing base under our revolving credit facility was increased from $425 million to $475 million.

Recent operational results, with applicable comparisons to fourth quarter 2013 results, and highlights were as follows:

• First quarter production was 21,133 barrels of oil equivalent (BOE) per day (BOEPD), up six percent compared to 20,020 BOEPD. • First quarter production from our Eagle Ford Shale operations was 15,152 BOEPD, up 15 percent compared to 13,145 BOEPD.• First quarter oil production was a record 11,955 barrels of oil per day (BOPD), an increase of seven percent compared to 11,130 BOPD.• In the Eagle Ford Shale, as of March 31, 2014, we had a total of 19 (11.1 net) wells completing or waiting on completion and six (3.4 net) wells being drilled.• Currently, we have a total of approximately 125,300 gross (85,900 net) acres in the Eagle Ford Shale. • Approximately 6,400 net acres, or eight percent, have been added in the Eagle Ford Shale since our last quarterly report at an average cost of approximately $3,000 per acre.• In both the Lower and Upper Eagle Ford Shale, we now estimate that we have approximately 1,510 gross remaining drilling locations, approximately 1,035 of which are in the Lower Eagle Ford Shale and approximately 475 of which are in the Upper Eagle Ford Shale.  • This inventory increased approximately 34 percent from approximately 1,125 locations reported previously.• This inventory does not assume any overlapping inventory from the Upper and Lower Eagle Ford Shale intervals, which may represent as many as 400 additional locations.• Approximately 90 locations were reclassified from Lower Eagle Ford Shale to Upper Eagle Ford Shale in the southeastern portion of our acreage in Lavaca County.• We recently drilled and completed the Welhausen Upper and Lower Eagle Ford Shale test wells in Lavaca County. The Lower Eagle Ford Shale well tested at 1,536 BOEPD and the Upper Eagle Ford Shale well tested at 2,165 BOEPD.

Definitions of non-GAAP financial measures and reconciliations of these non-GAAP financial measures to GAAP-based measures appear later in this release.

Management Comment

"We are pleased with our financial results in the first quarter as our cash flow and margins remained strong," said H. Baird Whitehead, President and Chief Executive Officer. "Despite a sizeable number of well completions coming online later than expected, we achieved a new quarterly oil production record. Due to continued success in adding to our Eagle Ford Shale acreage position, we are increasing our leasing capital expenditures guidance for the year, but otherwise our previously reported guidance remains unchanged. We continue our aggressive Eagle Ford Shale leasing effort, at attractive acquisition costs, as we draw closer to our stated minimum goal of 100,000 net acres.  

"Initial testing of our adjacent Upper / Lower Eagle Ford Shale wells commenced in the first quarter and the initial results are strong.  We saw initial production in excess of 2,000 BOEPD with a very high flowing pressure. Longer term testing will be necessary in order to fully understand the upside associated with the Upper Eagle Ford Shale, but we are very optimistic about the play."

First Quarter 2014 Results

Overview of Results

Operating income of $14.9 million in the first quarter of 2014, excluding $57.4 million of gain on the sale of assets, was $0.6 million lower than $15.5 million in the fourth quarter of 2013, excluding $0.2 million of gain on the sale of assets. This slight decrease was due primarily to a $5.7 million increase in exploration expense, a $4.9 million increase in depreciation, depletion and amortization (DD&A) expense, a $4.4 million increase in production and ad valorem taxes and a $3.2 million increase in share-based compensation expenses. The effect of these increased expenses was largely offset by a $16.1 million increase in product revenues, a $1.0 million decrease in recurring general and administrative (G&A) expense and a $0.4 million decrease in lease operating, gathering, processing and transportation expenses.

Product Revenues

Total product revenues were $133.2 million in the first quarter of 2014, a 14 percent increase compared to $117.1 million in the fourth quarter of 2013, due primarily to a 10 percent increase in average product pricing to $70.01 per BOE from $63.58 per BOE, as well as a three percent increase in equivalent production. The realized oil price was four percent higher than in the fourth quarter. Oil and NGL revenues were $114.9 million in the first quarter, a nine percent increase compared to $105.0 million in the fourth quarter, due to a five percent increase in combined oil and NGL prices, as well as a four percent increase in combined oil and NGL production. Oil and NGL revenues were 86 percent of product revenues in the first quarter, compared to 90 percent in the fourth quarter. Natural gas revenues were $18.2 million in the first quarter, a 51 percent increase compared to $12.0 million in the fourth quarter, due to a 47 percent increase in natural gas prices, as well as a three percent increase in natural gas production.

Production            
 Total and Daily Equivalent Production for the Three Months Ended
 Mar. 31,Dec. 31,Sept. 30,Mar. 31,Dec. 31,Sept. 30,
Region / Play Type201420132013201420132013
  (in MBOE) (in BOEPD)
             
Eagle Ford Shale 1,364 1,209 1,156 15,152 13,145 12,560
East Texas 180 241 246 2,004 2,624 2,675
Mid-Continent 174 204 219 1,931 2,213 2,385
Mississippi 178 181 179 1,981 1,969 1,951
Appalachia 6 6 6 66 68 67
Totals1,9021,8421,80721,13320,02019,638
             
Note - Numbers may not add due to rounding. MBOE equals one thousand barrels of oil equivalent.


As shown in the table above, production in the first quarter of 2014 was 21,133 BOEPD, compared to 20,020 BOEPD in the fourth quarter of 2013. As a percentage of total equivalent production, oil and NGL volumes were 69 percent in the first quarter of 2014, compared to 68 percent in the fourth quarter of 2013. 

Pricing

Our first quarter 2014 realized oil price was $98.12 per barrel, compared to $94.66 per barrel in the fourth quarter of 2013. Our first quarter 2014 realized NGL price was $41.27 per barrel, compared to $34.56 per barrel in the fourth quarter. Our first quarter 2014 realized natural gas price was $5.07 per thousand cubic feet (Mcf), compared to $3.45 per Mcf in the fourth quarter. Adjusting for oil and gas hedges, our first quarter 2014 effective oil price was $96.00 per barrel and our first quarter 2014 effective natural gas price was $4.85 per Mcf, or a decrease of $2.12 per barrel from the realized oil price and a decrease of $0.22 per Mcf in the realized gas price.

Operating Expenses

As discussed below, first quarter 2014 total direct operating expenses, excluding share-based compensation expenses, increased by $2.8 million to $30.6 million, or $16.08 per BOE produced, compared to $27.8 million, or $15.09 per BOE, in the fourth quarter of 2013.

• Lease operating expenses decreased by $0.2 million to $10.4 million, or $5.47 per BOE, from $10.6 million, or $5.74 per BOE, due primarily to lower down-hole maintenance and environmental compliance costs, partially offset by higher compression costs.• Gathering, processing and transportation expenses decreased by $0.3 million to $3.0 million, or $1.56 per BOE, compared to $3.2 million, or $1.76 per BOE, related primarily to lower processing costs attributable to overall NGL production, partially offset by higher gathering costs.• Production and ad valorem taxes increased by $4.4 million to $7.3 million, or 5.5 percent of product revenues, from $2.9 million, or 2.5 percent of product revenues, due primarily to higher overall production and the effect of ad valorem tax adjustments recorded in the fourth quarter of 2013.• G&A expense, excluding share-based compensation expenses of $6.8 million, decreased by $1.0 million to $9.9 million, or $5.21 per BOE, from $10.9 million, or $5.93 per BOE, excluding share-based compensation expenses and acquisition transaction expenses totaling $3.8 million. The increase in share-based compensation expenses was due to the increase in our common stock price during the first quarter of 2014.

Exploration expense increased to $8.6 million in the first quarter of 2014 from $2.9 million in the fourth quarter of 2013, primarily due to the acquisition of additional seismic in our Eagle Ford Shale area of interest.

DD&A expense increased by $5.0 million to $72.2 million, or $37.95 per BOE, in the first quarter of 2014, from $67.2 million, or $36.51 per BOE, in the fourth quarter of 2013, due primarily to higher overall production and a greater concentration of oil production from higher development-cost oil wells.

Capital Expenditures

During the first quarter of 2014, capital expenditures were approximately $182 million, an increase of $32 million, or 21 percent, compared to $150 million in the fourth quarter of 2013, consisting of:

$135 million for drilling and completion activities, compared to $104 million in the fourth quarter;•$37 million for leasehold acquisitions, compared to $40 million in the fourth quarter; and•$10 million for pipeline, gathering, facilities, seismic and other, compared to $6 million in the fourth quarter.

Capital Resources and Liquidity, Interest Expense and Impact of Derivatives

As of March 31, 2014, we had total debt of $1,265 million, consisting of $300 million principal amount of 7.25 percent senior unsecured notes due 2019, $775 million principal amount of 8.50 percent senior unsecured notes due 2020 and $190 million outstanding under our revolving credit facility (Revolver). Our leverage ratio under the Revolver was 3.6 times trailing twelve months' pro forma Adjusted EBITDAX of approximately $353 million, compared to 3.7 times at December 31, 2013. In May 2014, the borrowing base under the Revolver was increased from $425 million to $475 million. 

During the first quarter, interest expense was $22.5 million, of which $21.5 million was cash interest expense, compared to $22.3 million in the fourth quarter.

During the first quarter, derivatives loss was $15.7 million, compared to derivatives income of $2.4 million in the fourth quarter. First quarter 2014 cash settlements of derivatives resulted in net cash outlays of $3.1 million, compared to $2.7 million of net cash outlays in the fourth quarter.

Derivatives Update

To support our operating cash flows, we hedge a portion of our oil and natural gas production at pre-determined prices or price ranges. Based on hedges currently in place, we have hedged approximately 11,700 barrels of daily crude oil production, or approximately 67 percent of the midpoint of guidance for the final three quarters of 2014, at a weighted average floor/swap price of $92.94 per barrel. For 2015, we have hedged approximately 10,000 barrels of daily crude oil production at a weighted average floor/swap price of $89.41 per barrel.

We have also hedged approximately 11,700 MMBtu of daily natural gas production, or approximately 29 percent of the midpoint of guidance for the final three quarters of 2014, at a weighted average floor/swap price of $4.16 per MMBtu. For the first quarter of 2015, we have hedged 5,000 MMBtu of daily natural gas production at a weighted average floor/swap price of $4.50 per MMBtu.

Please see the Derivatives Table included in this release for our current derivative positions.

Eagle Ford Shale Operational Update

First Quarter 2014 Update

First quarter production of our Eagle Ford Shale operations was 15,152 BOEPD, up 15 percent compared to 13,145 BOEPD in the fourth quarter. First quarter oil production of our Eagle Ford Shale operations was 11,878 BOPD, 10 percent higher than 10,759 BOPD in the fourth quarter of 2013. 

During the first quarter, we completed 16 (12.9 net) operated wells and participated in the completion of two (0.9 net) outside operated wells. As of March 31, 2014, we had 19 (11.1 net) wells completing or waiting on completion and six (3.4 net) wells being drilled.

Upper Eagle Ford (Marl) Shale Update

The Welhausen #A2H and Welhausen #B1H located in Lavaca County were completed and turned in line during March 2014. The two laterals are effectively 660 feet apart. The Welhausen #B1H landed in the Lower Eagle Ford Shale, which is where the vast majority of our wells traditionally have been completed. The Welhausen #B1H has a 5,584 foot lateral and 26 frac stages and flowed back at a pressure of 5,700 pounds per square inch (psi), with an initial potential (IP) of 1,536 BOEPD. The Welhausen #A2H was completed in the Upper Eagle Ford (Marl) Shale.  The Welhausen #A2H has a 5,976 foot lateral and also has 26 frac stages.  The Welhausen #A2H flowed back at a pressure of 4,500 and had an IP of 2,165 BOEPD. After a recent clean-out operation of both wells, including the removal of plugs associated with eight frac stages in the Welhausen #A2H, the wells were just turned back in line.

These two wells have two of the highest wellhead flowing pressures we have encountered to date in our Eagle Ford Shale development program. Their GORs (gas-oil-ratios) of 5,000 to 6,000 standard cubic feet per barrel are also the highest we have encountered, but these higher pressures and GORs were expected since these wells are also our deepest "down-dip" tests of the Eagle Ford Shale. These initial results imply that we are still in the volatile oil window.  Longer term, additional testing and production history will help determine whether, at least in this area, the Upper Eagle Ford Shale and Lower Eagle Ford Shale are completely separate reservoirs. 

With continued leasing contiguous to our current acreage positions, along with the continued success of our multi-well pad drilling efforts and closer well spacing, we anticipate that, over time, additional wells will be added to our approximate 1,510 well drilling inventory.

Below are the results and statistics for recent Eagle Ford Shale wells:

                 
     Peak Gross Daily30-Day Average Gross Daily 
     Production Rates(1)Production Rates(1)
Well NameLateral

Length 
Frac

Stages
Oil

Rate
Equivalent

Rate
Equivalent Rate per

Frac Stage 
Oil

Rate
Equivalent

Rate
Equivalent Rate per 

Frac Stage
 Feet  BOPDBOEPDBOEPD/stageBOPDBOEPDBOEPD/stage
Operated wells                
Pavlicek #2H 5,394 24 1,057 1,319 55.0 455 624 26.0
Pavlicek #5H 4,496 20 1,112 1,411 70.6 451 614 30.7
Zebra Hunter #2H 6,697 29 1,301 1,511 52.1 1,000 1,118 38.6
Zebra Hunter #3H 6,518 28 2,001 2,250 80.4 1,222 1,350 48.2
Kusak #2H 7,693 33 911 982 29.8 610 655 19.8
Kusak #3H 8,182 32 765 830 25.9 625 674 21.1
Berger-Simper #2H 3,603 17 728 979 57.6 407 538 31.6
Berger-Simper #1H 5,296 24 935 1,361 56.7 464 636 26.5
Leal #3H 5,315 25 1,003 1,365 54.6 629 815 32.6
Leal #4H 6,390 23 1,224 1,641 71.3 594 735 32.0
Miller 2 #2H 4,418 20 577 626 31.3 442 466 23.3
Miller 2--#1H 4,977 23 759 818 35.5 458 486 21.1
Technik #2H 4,676 22 858 1,088 49.4 577 703 32.0
Technik #7H 4,539 21 609 819 39.0 428 520 24.8
Welhausen #A2H(2) 5,976 26 1,086 2,165 83.3 -- -- --
Welhausen #B1H(2) 5,584 26 807 1,536 59.1 -- -- --
                 
(1) Wellhead rates only; the natural gas associated with these wells is yielding between 145 and 165 barrels of NGLs per million cubic feet.
(2) After a recent clean-out operation of both wells, including the removal of plugs associated with eight frac stages in the Welhausen #A2H, the wells were just turned back in line and both are producing from 26 frac stages. 


Full-Year 2014 Guidance

Our 2014 capital expenditures are expected to range between $595 and $653 million, an increase of $13 to $20 million from previous guidance. This reflects an increase in lease acquisition capital expenditures to $60 to $83 million from previous guidance of $40 to $70 million. Other 2014 guidance remains unchanged.

Please see the Guidance Table included in this release for guidance estimates for full-year 2014. These estimates are meant to provide guidance only and are subject to revision as our operating environment changes.

Explanation of Non-GAAP Cash Margin per BOE

Cash Margin per BOE is a non-GAAP financial measure which represents total product revenues less total direct operating expenses, excluding share-based compensation expenses. Cash Margin per BOE is equal to cash margin divided by total equivalent crude oil, NGL and natural gas production. Cash Margin per BOE is not adjusted for the impact of hedges. Cash Margin per BOE is not a measure of financial performance under GAAP and should not be considered as an alternative to operating income. We believe that Cash Margin per BOE is an important measure that can be used by security analysts and investors to evaluate our cash operating margin and to compare it to other oil and gas companies, as well as for comparisons to other time periods.

First Quarter 2014 Conference Call

A conference call and webcast, during which management will discuss first quarter 2014 financial and operational results, is scheduled for Tuesday, May 13, 2014 at 10:00 a.m. ET. Prepared remarks by H. Baird Whitehead, President and Chief Executive Officer, will be followed by a question and answer period. Investors and analysts may participate via phone by dialing toll free 1-877-316-5288 (international: 1-734-385-4977) five to 10 minutes before the scheduled start of the conference call (use the conference code 3581559), or via webcast by logging on to our website, www.pennvirginia.com, at least 15 minutes prior to the scheduled start of the call to download and install any necessary audio software. A telephonic replay will be available for two weeks beginning approximately 24 hours after the call. The replay can be accessed by dialing toll free 1-855-859-2056 (international: 1-404-537-3406) and using the replay code 3581559. In addition, an on-demand replay of the webcast will also be available for two weeks at our website beginning approximately 24 hours after the webcast.

Penn Virginia Corporation(NYSE:PVA) is an independent oil and gas company engaged in the exploration, development and production of oil, NGLs and natural gas in various domestic onshore regions of the United States, with a primary focus in south and east Texas. For more information, please visit our website at www.pennvirginia.com.

Certain statements contained herein that are not descriptions of historical facts are "forward-looking" statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Because such statements include risks, uncertainties and contingencies, actual results may differ materially from those expressed or implied by such forward-looking statements. These risks, uncertainties and contingencies include, but are not limited to, the following: the volatility of commodity prices for oil, natural gas liquids, or NGLs, and natural gas; our ability to develop, explore for, acquire and replace oil and natural gas reserves and sustain production; our ability to generate profits or achieve targeted reserves in our development and exploratory drilling and well operations; any impairments, write-downs or write-offs of our reserves or assets; the projected demand for and supply of oil, NGLs and natural gas; reductions in the borrowing base under our revolving credit facility; our ability to contract for drilling rigs, supplies and services at reasonable costs; our ability to obtain adequate pipeline transportation capacity for our oil and gas production at reasonable cost and to sell the production at, or at reasonable discounts to, market prices; the uncertainties inherent in projecting future rates of production for our wells and the extent to which actual production differs from estimated proved oil and natural gas reserves; drilling and operating risks; our ability to compete effectively against other independent and major oil and natural gas companies; our ability to successfully monetize select assets and repay our debt; leasehold terms expiring before production can be established; environmental liabilities that are not covered by an effective indemnity or insurance; the timing of receipt of necessary regulatory permits; the effect of commodity and financial derivative arrangements; our ability to maintain adequate financial liquidity and to access adequate levels of capital on reasonable terms; the occurrence of unusual weather or operating conditions, including force majeure events; our ability to retain or attract senior management and key technical employees; counterparty risk related to their ability to meet their future obligations; changes in governmental regulations or enforcement practices, especially with respect to environmental, health and safety matters; uncertainties relating to general domestic and international economic and political conditions; and other risks set forth in our filings with the Securities and Exchange Commission (SEC).

Additional information concerning these and other factors can be found in our press releases and public periodic filings with the SEC. Many of the factors that will determine our future results are beyond the ability of management to control or predict. Readers should not place undue reliance on forward-looking statements, which reflect management's views only as of the date hereof. We undertake no obligation to revise or update any forward-looking statements, or to make any other forward-looking statements, whether as a result of new information, future events or otherwise.

 
PENN VIRGINIA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - unaudited
(in thousands, except per share data)
       
  Three months ended Three months ended
 March 31,December 31,
  2014 2013 2013
Revenues      
Crude oil  $ 105,576  $ 63,058  $ 96,918
Natural gas liquids (NGLs)  9,373  7,127  8,096
Natural gas  18,203  12,039  12,073
 Total product revenues  133,152  82,224  117,087
(Loss) gain on sales of property and equipment, net  56,826  (549)  213
Other  (113)  1,523  (298)
 Total revenues  189,865  83,198  117,002
Operating expenses      
Lease operating  10,404  7,805  10,570
Gathering, processing and transportation  2,961  3,579  3,241
Production and ad valorem taxes  7,305  5,959  2,872
General and administrative  9,918  9,858  11,115
Share-based compensation - liability-classified awards (a)  5,945  --  2,607
 Total direct operating expenses  36,533  27,201  30,405
Share-based compensation - equity-classified awards (b)  825  1,085  1,000
Exploration   8,636  6,295  2,897
Depreciation, depletion and amortization  72,187  51,576  67,239
 Total operating expenses  118,181  86,157  101,541
       
Operating income (loss)  71,684  (2,959)  15,461
       
Other income (expense)      
Interest expense   (22,534)  (14,479)  (22,336)
Loss on extinguishment of debt  --  --  (17)
Derivatives  (15,662)  (7,761)  2,356
Other  1  27  68
       
Income (loss) before income taxes   33,489  (25,172)  (4,468)
Income tax (expense) benefit  (14,264)  8,789  2,119
Net income (loss)  19,225  (16,383)  (2,349)
Preferred stock dividends  (1,722)  (1,725)  (1,725)
       
Net income (loss) attributable to common shareholders  $ 17,503  $ (18,108)  $ (4,074)
       
Net income (loss) per share:      
Basic  $ 0.27  $ (0.33)  $ (0.06)
Diluted  $ 0.22  $ (0.33)  $ (0.06)
       
Weighted average shares outstanding, basic   65,611  55,341  65,490
Weighted average shares outstanding, diluted  85,744  55,341  65,490
       
       
  Three months ended Three months

ended
 March 31,December 31,
  2014 2013 2013
Production      
Crude oil (MBbls)  1,076  599  1,024
NGLs (MBbls)  227  234  234
Natural gas (MMcf)  3,593  3,565  3,502
Total crude oil, NGL and natural gas production (MBOE)  1,902  1,427  1,842
       
Prices      
Crude oil ($ per Bbl)  $ 98.12  $ 105.28  $ 94.66
NGLs ($ per Bbl)  $ 41.27  $ 30.45  $ 34.56
Natural gas ($ per Mcf)  $ 5.07  $ 3.38  $ 3.45
       
Prices - Adjusted for derivative settlements      
Crude oil ($ per Bbl)  $ 96.00  $ 109.97  $ 91.48
NGLs ($ per Bbl)  $ 41.27  $ 30.45  $ 34.56
Natural gas ($ per Mcf)  $ 4.85  $ 3.59  $ 3.61
       
(a) Includes liability-classified share-based compensation expense attributable to our performance-based restricted stock units which are payable in cash upon the achievement of certain market-based performance metrics. A total of $5.9 million and less than $0.1 million attributable to these awards is included in the three months ended March 31, 2014 and 2013.
(b) Our equity-classified share-based compensation expense includes non-cash charges for our stock option expense and the amortization of common, deferred and restricted stock and restricted stock unit awards related to equity-classified employee and director compensation in accordance with accounting guidance for share-based payments.
   
PENN VIRGINIA CORPORATION  
CONDENSED CONSOLIDATED BALANCE SHEETS - unaudited  
(in thousands)  
  As of   
 March 31,December 31,  
  2014 2013  
Assets      
Current assets  $ 188,246  $ 233,696  
Net property and equipment  2,312,003  2,237,304  
Other assets  35,684  36,087  
Total assets  $ 2,535,933  $ 2,507,087  
       
Liabilities and shareholders' equity      
Current liabilities  257,815  258,145  
Revolving credit facility  190,000  206,000  
Senior notes due 2019  300,000  300,000  
Senior notes due 2020  775,000  775,000  
Other liabilities and deferred income taxes  204,875  179,138  
Total shareholders' equity  808,243  788,804  
Total liabilities and shareholders' equity  $ 2,535,933  $ 2,507,087  
     
       
       
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - unaudited
(in thousands)
       
  Three months ended Three months ended
 March 31,December 31,
  2014 2013 2013
Cash flows from operating activities      
Net income (loss)  $ 19,225  $ (16,383)  $ (2,349)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:      
Loss on extinguishment of debt  --  --  17
Depreciation, depletion and amortization  72,187  51,576  67,239
Accretion of firm transportation obligation  354  207  411
Derivative contracts:      
Net losses (gains)  15,662  7,761  (2,356)
Cash settlements, net  (3,057)  3,557  (2,667)
Deferred income tax expense (benefit)  14,064  (8,789)  (2,119)
(Gain) loss on sales of assets, net  (56,826)  549  (213)
Non-cash exploration expense  3,294  5,262  3,284
Non-cash interest expense  1,012  946  998
Share-based compensation (equity-classified)  825  1,085  1,000
Other, net  206  81  99
Changes in operating assets and liabilities  (386)  (237)  (26,666)
Net cash provided by operating activities  66,560  45,615  36,678
Cash flows from investing activities      
Acquisition, net  --  --  20,568
Capital expenditures - property and equipment  (159,804)  (85,973)  (147,239)
Proceeds from sales of assets, net  95,964  878  (707)
Net cash used in investing activities  (63,840)  (85,095)  (127,378)
Cash flows from financing activities      
Proceeds from revolving credit facility borrowings  85,000  38,000  83,000
Repayment of revolving credit facility borrowings  (101,000)  --  (5,000)
Debt issuance costs paid  --  --  (435)
Dividends paid on preferred and common stock  (1,725)  (1,687)  (1,725)
Other, net  1,085  (61)  13
Net cash (used in) provided by financing activities  (16,640)  36,252  75,853
Net decrease in cash and cash equivalents  (13,920)  (3,228)  (14,847)
Cash and cash equivalents - beginning of period  23,474  17,650  38,321
Cash and cash equivalents - end of period  $ 9,554  $ 14,422  $ 23,474
       
Supplemental disclosures of cash paid for:      
Interest  $ 1,025  $ 340  $ 43,303
Income taxes (net of refunds received)  $ --   $ --   $ -- 
 
PENN VIRGINIA CORPORATION
CERTAIN NON-GAAP FINANCIAL MEASURES - unaudited
(in thousands)
       
       
  Three months ended Three months ended
 March 31,December 31,
  2014 2013 2013
Reconciliation of GAAP "Net income (loss) " to Non-GAAP "Net income (loss) applicable to common shareholders, as adjusted"
Net income (loss)  $ 19,225  $ (16,383)  $ (2,349)
Adjustments for derivatives:      
 Net losses (gains)  15,662  7,761  (2,356)
 Cash settlements, net  (3,057)  3,557  (2,667)
Adjustment for acquisition transaction expenses  --   --   191
Adjustment for restructuring costs  12  --   2
Adjustment for (gain) loss on sale of assets, net  (56,826)  549  (213)
Adjustment for loss on extinguishment of debt  --   --   17
Impact of adjustments on income taxes  18,830  (4,143)  2,384
Preferred stock dividends  (1,722)  (1,725)  (1,725)
Net loss applicable to common shareholders, as adjusted (a)  $ (7,876)  $ (10,384)  $ (6,716)
       
Net loss applicable to common shareholders, as adjusted, per share, diluted   $ (0.12)  $ (0.19)  $ (0.10)
       
Reconciliation of GAAP "Net income (loss)" to Non-GAAP "Adjusted EBITDAX"    
Net income (loss)  $ 19,225  $ (16,383)  $ (2,349)
Income tax benefit  14,264  (8,789)  (2,119)
Interest expense  22,534  14,479  22,336
Depreciation, depletion and amortization  72,187  51,576  67,239
Exploration  8,636  6,295  2,897
Share-based compensation expense (equity-classified awards)  825  1,085  1,000
EBITDAX  137,671  48,263  89,004
Adjustments for derivatives:      
 Net losses (gains)  15,662  7,761  (2,356)
 Cash settlements, net  (3,057)  3,557  (2,667)
Adjustment for acquisition transaction expenses  --   --   191
Adjustment for (gain) loss on sale of assets, net  (56,826)  549  (213)
Adjustment for other non-cash items  354  207  411
Adjustment for loss on extinguishment of debt  --   --   17
Adjusted EBITDAX (b)  93,804  60,337  84,387
Pro forma EBITDAX from our 2013 Eagle Ford Shale acquisition   --   22,649  -- 
Pro forma Adjusted EBITDAX  $ 93,804  $ 82,986  $ 84,387
       
(a) Net loss applicable to common shareholders, as adjusted, represents net loss, less preferred stock dividends, adjusted to exclude the effects, net of income taxes, of non-cash changes in the fair value of derivatives, acquisition transaction expenses, restructuring costs, net gains and losses on the sale of assets and loss on extinguishment of debt. We believe this presentation is commonly used by investors and professional research analysts in the valuation, comparison, rating and investment recommendations of companies within the oil and gas exploration and production industry. We use this information for comparative purposes within our industry. Net loss applicable to common shareholders, as adjusted, is not a measure of financial performance under GAAP and should not be considered as a measure of liquidity or as an alternative to net loss applicable to common shareholders.



(b) Adjusted EBITDAX represents net loss before income tax benefit, interest expense, depreciation, depletion and amortization expense, exploration expense and share-based compensation expense, further adjusted to exclude the effects of non-cash changes in the fair value of derivatives, acquisition transaction expenses, impairments, net gains and losses on the sale of assets, loss on extinguishment of debt, loss on firm transportation commitment and other non-cash items. We believe this presentation is commonly used by investors and professional research analysts in the valuation, comparison, rating and investment recommendations of companies within the oil and gas exploration and production industry. We use this information for comparative purposes within our industry. Adjusted EBITDAX is not a measure of financial performance under GAAP and should not be considered as a measure of liquidity or as an alternative to net loss. Pro forma Adjusted EBITDAX further adjusts Adjusted EBITDAX to include the pro forma EBITDAX from our Eagle Ford Shale acquisition in April 2013 and represents EBITDAX as defined in our revolving credit facility.
 
PENN VIRGINIA CORPORATION
GUIDANCE TABLE - unaudited
(dollars in millions except where noted)
         
We are providing the following guidance regarding financial and operational expectations for full-year 2014. These estimates are meant to provide guidance only and are subject to change as PVA's operating environment changes.
         
         
         
  First      
  Quarter Full-Year
  2014 2014 Guidance
Production:        
Crude oil (MBbls) 1,076 5,700  --  6,100
NGLs (MBbls)  227 1,075  --  1,175
Natural gas (MMcf)  3,593 14,000  --  15,000
Equivalent production (MBOE) 1,902 9,108  --  9,775
Equivalent daily production (BOEPD) 21,133 24,954  --  26,781
Percent crude oil and NGLs 68.5% 69.3%  --  79.9%
         
Production revenues (a):        
Crude oil   $ 105.6 500.0  --  535.0
NGLs   $ 9.4 32.0  --  35.0
Natural gas  $ 18.2 55.0  --  60.0
Total product revenues  $ 133.2 587.0  --  630.0
Total product revenues ($ per BOE)  $ 70.01 60.05  --  69.17
Percent crude oil and NGLs 86.3% 84.4%  --  97.1%
         
Operating expenses:        
 Lease operating ($ per BOE)  $ 5.47 5.80  --  6.40
 Gathering, processing and transportation costs ($ per BOE)  $ 1.56 1.70  --  1.90
 Production and ad valorem taxes (percent of oil and gas revenues) 5.5% 6.5%  --  7.5%
         
General and administrative:        
 Recurring general and administrative  $ 9.9 40.0  --  43.0
 Share-based compensation  $ 6.8 12.0  --  15.0
 Acquisition transaction expenses  --  0.0  --  0.0
Total reported G&A  $ 16.7 52.0  --  58.0
         
Exploration:        
 Total reported exploration  $ 8.6 23.0  --  25.0
 Unproved property amortization  $ 3.3 12.5  --  13.0
         
Depreciation, depletion and amortization ($ per BOE)  $ 37.95 35.00  --  36.00
         
Adjusted EBITDAX (b)  $ 93.8 440.0  --  485.0
         
Capital expenditures:        
Drilling and completion  $ 135.5 510.0  --  540.0
Lease acquisitions  $ 36.9 60.0  --  83.0
Seismic (c)  $ 4.5 10.0  --  12.0
Pipeline, gathering, facilities and other  $ 5.6 15.0  --  18.0
 Total capital expenditures  $ 182.4 595.0  --  653.0
         
End of period debt outstanding  $ 1,265.0 1,390.0  --  1,450.0
Interest expense:        
 Total reported interest expense  $ 22.5 97.0  --  100.0
 Cash interest expense  $ 21.5 93.0  --  96.0
Preferred stock dividends paid  $ 1.7 6.9  --  6.9
Income tax benefit rate  42.6% 35.5%  --  37.5%
         
(a) Assumes average benchmark prices of $90.00 per barrel for crude oil and $4.50 per MMBtu for natural gas in the final three quarters of 2014, prior to any premium or discount for quality, basin differentials, the impact of hedges and other adjustments. NGL realized pricing is assumed to be $29.06 per barrel in the final three quarters of 2014.



(b) Adjusted EBITDAX is not a measure of financial performance under GAAP and should not be considered as a measure of liquidity or as an alternative to net income.



(c) Seismic expenditures are also reported as a component of exploration expense and as a component of net cash provided by operating activities.
 
PENN VIRGINIA CORPORATION
GUIDANCE TABLE - unaudited - (continued)
         
Note to Guidance Table:        
         
The following table shows our current derivative positions.    
         
     Weighted Average Price
 Instrument TypeAverage Volume

Per Day
Floor/ SwapCeiling
         
Natural gas:  (MMBtu)($ / MMBtu)  
Second quarter 2014 Swaps 15,000 4.10  
Third quarter 2014 Swaps 15,000 4.10  
Fourth quarter 2014 Swaps 5,000 4.50  
First quarter 2015 Swaps 5,000 4.50  
         
Crude oil:  (barrels)($ / barrel)  
Second quarter 2014 Collars  2,500 92.00 99.46
Third quarter 2014 Collars  2,000 90.00 94.33
Fourth quarter 2014 Collars  2,000 90.00 94.33
First quarter 2015 Collars (a) 4,000 87.50 94.66
Second quarter 2015 Collars (a) 4,000 87.50 94.66
Third quarter 2015 Collars (a) 3,000 86.67 94.73
Fourth quarter 2015 Collars (a) 3,000 86.67 94.73
Second quarter 2014 Swaps 8,500 94.00  
Third quarter 2014 Swaps (a) 10,000 93.21  
Fourth quarter 2014 Swaps (a) 10,000 93.21  
First quarter 2015 Swaps (a) 7,000 90.79  
Second quarter 2015 Swaps (a) 7,000 90.79  
Third quarter 2015 Swaps (a) 6,000 90.45  
Fourth quarter 2015 Swaps (a) 6,000 90.45  
First quarter 2015 Swaption (b) 1,000 88.00  
Second quarter 2015 Swaption (b) 1,000 88.00  
Third quarter 2015 Swaption (b) 1,000 88.00  
Fourth quarter 2015 Swaption (b) 1,000 88.00  
         
         
(a) All or a portion of these derivatives have include "lower" puts sold at a strike price of $70 per barrel. If the price of WTI oil goes below $70 per barrel, the cash receipts on the derivatives will be limited to the difference between the swap / floor price and $70 per barrel.
(b) This swaption contract gives our counterparties the option to enter into a fixed price swap with us at a future date. If the forward commodity price for calendar year 2015 is higher than or equal to $88.00 per barrel on December 31, 2014, the counterparty will exercise its option to enter into a fixed price swap at $88.00 per barrel for calendar year 2015, at which point the contract functions as a fixed price swap. If the forward commodity price for calendar year 2015 is lower than $88.00 per barrel on December 31, 2014, the option expires and no fixed price swap is in effect.
We estimate that, excluding the derivative positions described above, for every $10.00 per barrel increase or decrease in the crude oil price, operating income for the final three quarters of 2014 would increase or decrease by approximately $41.0 million. In addition, we estimate that, excluding the derivative positions described above, for every $1.00 per MMBtu increase or decrease in the natural gas price, operating income for the final three quarters of 2014 would increase or decrease by approximately $10.6 million. This assumes that crude oil prices, natural gas prices and inlet volumes remain constant at anticipated levels. These estimated changes in operating income exclude potential cash receipts or payments in settling these derivative positions.

CONTACT: James W. Dean Vice President, Corporate Development Ph: (610) 687-7531 Fax: (610) 687-3688 E-Mail: invest@pennvirginia.com



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