News Column

Penn Virginia Corporation Announces Second Quarter 2014 Results

July 30, 2014

RADNOR, Pa., July 30, 2014 (GLOBE NEWSWIRE) -- Penn Virginia Corporation (NYSE:PVA) today reported financial results for the three months ended June 30, 2014 and provided updates of its operations, 2014 guidance and 2015 preliminary guidance.

Key Highlights

• Second quarter production from Eagle Ford Shale operations increased six percent to 15,618 barrels of oil equivalent per day (BOEPD) compared to 14,761 BOEPD in the prior quarter. • Since our last quarterly report, our operated Eagle Ford wells had an average initial potential (IP) of 1,514 BOEPD (excluding shallow wells), including one well with an IP of 3,175 BOEPD.• Our Upper Eagle Ford well production is exceeding expectations.• Adjusted second quarter EBITDAX, a non-GAAP (generally accepted accounting principles) measure, grew to $95.0 million from $93.8 million in the first quarter.• Currently in the Eagle Ford we have 11 (6.3 net) wells completing, 11 (5.0 net) wells waiting on completion and six (4.6 net) wells being drilled.• Currently in the Eagle Ford we have approximately 143,200 (102,000 net) acres, including the recently announced acquisition of 13,125 (11,660 net) acres for $45 million. • Including this pending acquisition, approximately 16,100 net acres, or 19 percent, have been added in the Eagle Ford since our last quarterly report at an average cost of approximately $3,700 per acre.• We have increased our undrilled location inventory from approximately 1,510 to approximately 1,635 locations.• As separately announced, we today closed a $150 million sale of the rights to construct and operate a crude oil gathering and intermediate transportation system in the Eagle Ford.• We are increasing our rig count in the Eagle Ford to eight in the second half of 2014. • Incremental capital expenditures will be funded by our recently completed $325 million convertible preferred equity offering and non-core asset sales.• We have updated our guidance for full-year 2014 and updated our preliminary guidance for full-year 2015. • We decreased our guidance for 2014 production to between 8.8 and 9.2 million BOE (MMBOE), due primarily to less than expected production during the first half of 2014; we reaffirmed our 2014 Adjusted EBITDAX guidance.• We increased our preliminary guidance for 2015 production growth over 2014 to approximately 45 percent for oil and approximately 35 percent overall; we increased guidance for our 2015 Adjusted EBITDAX growth over 2014 to between 35 and 40 percent.

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

H. Baird Whitehead, President and Chief Executive Officer, stated, "In the second quarter of 2014, our cash flows and margins remained strong and were in line with our expectations, despite our production being challenged by the timing and operational complexities associated with pad drilling and completions. We have expanded our ongoing pad drilling program in the Eagle Ford and are encouraged by our recent results in the play, especially our results in the Upper Eagle Ford. We are modestly reducing our full year production guidance, but we remain confident that we can deliver significantly higher production levels in the second half of 2014 as we realize the ongoing benefit of our pad completions and rig expansions along with an increased focus on the Upper Eagle Ford."

Whitehead continued, "We are very pleased with the results of the oil gathering and transportation rights sale, which is another step forward in our efforts to improve our liquidity and fund additional investment and further growth in the Eagle Ford. This transaction, along with the pending sale of our Mississippi assets, brings the total proceeds from 2014 asset sales to $319 million, exceeding our original goal of up to $300 million."

Whitehead concluded, "These asset sales and the convertible preferred offering provide us with the financial flexibility to fund operations through 2015, while also allowing us to significantly reduce our leverage ratio. We are increasing our capital expenditures in the second half to support the addition of two new rigs, which will position us to realize improved production in the second half and approximately 45 percent growth in oil production for 2015. We are excited about our future prospects and are committed to executing our strategic plan to deliver significant long-term shareholder value."

Second Quarter 2014 Results

Overview of Results

Operating income of $26.3 million in the second quarter of 2014, excluding $117.9 million of impairments, was $11.4 million higher than $14.9 million in the first quarter of 2014, excluding $56.8 million of gain on the sale of assets. This 77 percent increase was due primarily to a $6.4 million increase in product and other revenues, a $5.2 million decrease in exploration expense, a $4.9 million decrease in share-based compensation expenses and a $0.8 million decrease in depletion, depreciation and amortization (DD&A) expense. The effect of these favorable increases was partially offset by a $3.1 million increase in general and administrative (G&A) expense, excluding share-based compensation expenses, and a $2.8 million increase in lease operating, gathering, processing and transportation expenses and production and ad valorem taxes.

Net loss attributable to common shareholders for the second quarter was $105.9 million, or $1.59 per diluted share, compared to net income of $17.5 million, or $0.22 per diluted share, in the prior quarter. Adjusted net loss attributable to common shareholders for the second quarter, a non-GAAP measure which includes our preferred stock dividend but excludes the effects of other items that affect comparability to other periods, was $4.3 million, or $0.07 per diluted share, compared to a loss of $7.9 million, or $0.12 per diluted share in the prior quarter.

Product Revenues

Total product revenues were $136.4 million, or $68.81 per barrel of oil equivalent (BOE), in the second quarter of 2014, a two percent increase compared to $133.2 million, or $70.01 per BOE, in the first quarter due primarily to a four percent increase in equivalent production and a two percent increase in the realized oil price, partially offset by a 25 percent decrease in the realized natural gas liquid (NGL) price and an 11 percent decrease in the realized natural gas price. Oil and NGL revenues were $120.1 million in the second quarter, a five percent increase compared to $114.9 million in the first quarter due to a six percent increase in combined oil and NGL production, partially offset by a one percent decrease in combined oil and NGL prices. Oil and NGL revenues were 88 percent of product revenues in the second quarter, compared to 86 percent in the first quarter. Natural gas revenues were $16.3 million in the second quarter, a 10 percent decrease compared to $18.2 million in the first quarter due to an 11 percent decrease in natural gas prices, partially offset by a one percent increase in natural gas production.

Production

As shown in the table below, production in the second quarter of 2014 was 21,786 BOEPD, compared to 21,133 BOEPD in the first quarter of 2014. As a percentage of total equivalent production, oil and NGL volumes were 70 percent in the second quarter of 2014, compared to 69 percent in the first quarter of 2014.

 Total and Daily Equivalent Production for the Three Months Ended
 June 30,Mar. 31,Dec. 31,June 30,Mar. 31,Dec. 31,
Region / Play Type201420142013201420142013
  (in MBOE) (in BOEPD)
             
Eagle Ford Shale 1,421 1,329 1,209 15,618 14,761 13,145
East Texas 220 215 241 2,417 2,394 2,624
Mid-Continent 161 174 204 1,770 1,931 2,213
Mississippi / Other  180 184 187 1,981 2,047 2,037
Totals1,9831,9021,84221,78621,13320,020
             
Note - Numbers may not add due to rounding. MBOE equals one thousand barrels of oil equivalent.


Operating Expenses

As discussed below, second quarter 2014 total direct operating expenses, excluding share-based compensation expenses, increased by $5.8 million to $36.4 million, or $18.36 per BOE produced, compared to $30.6 million, or $16.08 per BOE, in the first quarter of 2014.

• Lease operating expenses increased by $2.0 million to $12.4 million, or $6.25 per BOE, from $10.4 million, or $5.47 per BOE, due to higher water disposal, chemical, fuel and lubricant costs, as well as higher compression costs related to a new gathering and compression agreement following the first quarter 2014 sale of our natural gas midstream assets in the Eagle Ford.• Gathering, processing and transportation expenses increased by $0.6 million to $3.5 million, or $1.78 per BOE, compared to $2.9 million, or $1.56 per BOE, related to higher gas production volumes and increased transportation expense as a result of the new gathering and compression agreement.• Production and ad valorem taxes increased by $0.2 million to $7.5 million, or 5.5 percent of product revenues, from $7.3 million, or 5.5 percent of product revenues, due to higher product revenues.• G&A expense, excluding share-based compensation expenses of $1.9 million, increased by $3.1 million to $13.0 million, or $6.54 per BOE, from $9.9 million, or $5.21 per BOE, excluding share-based compensation expenses of $6.8 million. Approximately $1.1 million of the increase in G&A expense was due to non-recurring costs related to the replacement of our enterprise resource planning software, 2013-related arbitration costs and asset sale transactions. The decrease in share-based compensation expenses was due to a lower common stock price in the second quarter of 2014.

Exploration expense decreased to $3.4 million in the second quarter from $8.6 million in the first quarter, due primarily to decreased expenditures for seismic data.

DD&A expense decreased by $0.8 million to $71.4 million, or $36.03 per BOE, in the second quarter, from $72.2 million, or $37.95 per BOE, in the first quarter, due to lower depletion rates.

In the second quarter, we incurred a $117.9 million impairment charge as a result of writing down our Mississippi properties to fair value.

Capital Expenditures

During the second quarter of 2014, capital expenditures were $170 million, a decrease of $12 million, or seven percent, compared to $182 million in the first quarter of 2014, consisting of:

$154 million for drilling and completion activities, compared to $135 million in the first quarter;•$13 million for leasehold acquisitions, compared to $37 million in the first quarter; and•$3 million for pipeline, gathering, facilities, seismic and other, compared to $10 million in the first quarter.

Capital Resources and Liquidity, Interest Expense and Impact of Derivatives

As of June 30, 2014, we had total debt of $1,130 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 $55 million outstanding under our revolving credit facility (Revolver). In June 2014, we completed the offering of $325 million of Series B convertible perpetual preferred stock depositary shares. Moreover, year-to-date through June 30, 2014, approximately $26 million of our Series A convertible perpetual preferred stock depositary shares have converted into common shares. As a result, at June 30, 2014, we had outstanding convertible perpetual preferred stock depositary shares with a face value of approximately $414 million. Our leverage ratio under the Revolver at June 30, 2014 was 3.1 times trailing twelve months' pro forma Adjusted EBITDAX of approximately $362 million, compared to 3.6 times at March 31, 2014. 

As separately announced, we today closed a sale of our rights to construct and operate a crude oil gathering and intermediate transportation system covering a portion of our Eagle Ford acreage for $150 million, and we expect to close the sale of our Mississippi Selma Chalk producing properties on July 31, 2014 for a price of approximately $73 million, bringing year-to-date asset sale proceeds to approximately $319 million. Earlier this month, we also announced an approximate $45 million acquisition in the Eagle Ford, of which approximately $34 million will be paid up front and the $11 million balance will be a drilling carry. Pro forma for these transactions, our leverage ratio under the Revolver at June 30, 2014 was approximately 2.6 times. In July 2014, there was a favorable final settlement of arbitration of approximately $34 million related to our significant 2013 Eagle Ford acquisition.

During the second quarter, interest expense was $23.2 million, of which $22.2 million was cash interest expense, compared to $22.5 million in the first quarter.

During the second quarter, derivatives loss was $42.7 million, compared to derivatives loss of $15.7 million in the first quarter. Second quarter 2014 cash settlements of derivatives resulted in net cash outlays of $7.2 million, compared to $3.1 million of net cash outlays in the first quarter.

Pricing

Our second quarter 2014 realized oil price was $100.16 per barrel, compared to $98.12 per barrel in the first quarter of 2014. Our second quarter 2014 realized NGL price was $30.85 per barrel, compared to $41.27 per barrel in the first quarter. Our second quarter 2014 realized natural gas price was $4.51 per thousand cubic feet (Mcf), compared to $5.07 per Mcf in the first quarter. Adjusting for oil and gas hedges, our second quarter 2014 effective oil price was $94.72 per barrel and our second quarter 2014 effective natural gas price was $4.20 per Mcf, or a decrease of $5.44 per barrel from the realized oil price and a decrease of $0.31 per Mcf in the realized gas price.

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 12,500 barrels of daily crude oil production, or approximately 70 percent of the midpoint of guidance for the second half of 2014, at a weighted average floor/swap price of $92.80 per barrel. For 2015, we have hedged approximately 11,500 barrels of daily crude oil production at a weighted average floor/swap price of $90.17 per barrel. For 2016, we have hedged 3,000 barrels of daily crude oil production at a weighted average floor/swap price of $90.84 per barrel.

We have also hedged 10,000 MMBtu (million British Thermal Units) of daily natural gas production, or approximately 25 percent of the midpoint of guidance for the second half of 2014, at a weighted average floor/swap price of $4.20 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.

Full-Year 2014 and Preliminary Full-Year 2015 Guidance

2014 capital expenditures are expected to range between $762 and $808 million ($410 to $456 million for the second half of 2014), which is an increase of $155 to $167 million from previous guidance. This reflects increases in drilling and completion capital expenditures of between $125 and $130 million and in lease acquisition capital expenditures of between $32 and $37 million. The increase in drilling and completion expenditures is attributable to the addition of a seventh drilling rig in August 2014 and an eighth drilling rig estimated to commence drilling in September 2014. As a result of the additional rigs, we expect to turn in line 68 (39.0 net) wells during the remainder of 2014, for a total of 111 (67.0 net) operated wells (excludes shallow wells) to be turned in line during 2014, along with a production contribution associated with the seventh and eighth rigs of 700 to 800 MBOE in the fourth quarter of 2014.

2014 production is expected to range between approximately 8.8 and 9.2 MMBOE (5.0 to 5.3 MMBOE in the second half of 2014). This represents a decrease of between 7 and 290 MBOE from previous guidance, excluding approximately 260 MBOE of production from our Mississippi assets, the sale of which we expect to close on July 31, 2014. 2014 oil production is expected to range between approximately 5.3 and 5.6 million barrels of oil (3.1 to 3.4 MMBO in the second half of 2014). This represents a decrease of between 400 and 550 MBOE barrels from previous guidance and is due primarily to delays in the timing of completions during the first half of 2014 resulting from operational complexities associated with pad drilling and completions.

The company average production in July 2014, through July 25th, is estimated at 23,800 BOEPD, compared to 21,786 BOEPD for the second quarter. As the seventh and eighth drilling rigs are expected to be active by the end of the third quarter, a significant jump in production is expected to take place during the fourth quarter, while the third quarter is expected to show a modest increase over the second quarter.

2014 Adjusted EBITDAX, which includes the cash impact of derivatives, is expected to range between $425 and $500 million ($251 to $296 million during the second half of 2014), unchanged from previous guidance. We assume the benchmark (WTI) oil price will average $90 per barrel and the benchmark (Henry Hub) natural gas price will average $4.50 per MMBTU in the second half of 2014.

With the two additional drilling rigs, we now estimate total production growth of approximately 35 percent in 2015 and oil production growth of approximately 45 percent in 2015, as compared to previous guidance for total production growth in excess of 30 percent and oil production growth in excess of 40 percent, which assumed a seven drilling rig program.

We estimate that 2015 capital expenditures will range between $750 and $800 million and include approximately $710 to $750 million for drilling and completion expenditures. 2015 Adjusted EBITDAX is expected to be between 35 and 40 percent higher than 2014. We assume the WTI oil price will average $90 per barrel and the Henry Hub natural gas price will average $4.25 per MMBTU in 2015.

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.

Eagle Ford Shale Operational Update

Second Quarter 2014 Update

Second quarter production from our Eagle Ford operations was 15,618 BOEPD, up six percent compared to 14,761 BOEPD in the first quarter, 75 percent of which was crude oil. In June 2014, our average production was 16,861 BOEPD, 74 percent of which was from crude oil. Through July 25, 2014, our average Eagle Ford production in July 2014 is estimated at 18,100 BOEPD. Year-to-date, we have turned in line 43 (28.0 net) operated wells (excludes shallow wells). 

Below are the results and statistics for Eagle Ford wells over the past five quarters: (1)

   Averages
      Peak Gross Daily30-Day Average Gross Daily 
         Production Rates(2)Production Rates(2)
 Gross/Net

Wells
Lateral

Length 
Frac

Stages
ProppantOil

Rate
Equivalent

Rate
Oil

Percentage
Oil

Rate
Equivalent

Rate
Oil

Percentage
   Feet  lbs.BOPDBOEPD  BOPDBOEPD  
Time Period                    
2013 - 2nd quarter 14 / 8.6 5,588 23.0 5,184,664 1,181 1,397 85% 691 845 82%
2013 - 3rd quarter 10 / 5.6 5,901 23.8 6,526,680 1,375 1,596 86% 879 1,036 85%
2013 - 4th quarter 15 / 7.3 5,730 24.1 7,789,759 1,418 1,624 87% 960 1,119 86%
2014 - 1st quarter 14 / 10.2 5,836 25.2 7,791,564 1,159 1,457 80% 695 844 82%
2014 - 2nd quarter(3) 25 / 15.2 5,527 25.4 9,327,075 1,220 1,514 81% 727 948 77%
Totals and averages78 / 47.05,68024.57,653,2981,2601,51583%78995682%
                     
Operating Area                    
Shiner -- "Beer Quad" 17 / 8.0 5,970 26.4 9,350,587 1,581 1,899 83% 1,097 1,340 82%
Upper Eagle Ford(4) 2 / 1.9 5,917 26.5 9,970,830 917 1,763 52% 830 1,502 55%
Shiner - Mod. GOR 12 / 9.2 5,124 21.7 6,579,536 1,118 1,346 83% 628 763 82%
Peach Creek 25 / 11.7 6,002 25.2 7,229,596 1,352 1,493 91% 907 1,002 91%
Rock Creek / Bozka(3) 8 / 3.7 6,152 26.8 9,041,509 1,339 1,527 88% 848 955 89%
Shiner - High GOR 14 / 12.5 4,928 21.6 6,144,944 833 1,189 70% 500 706 70%
Totals and averages78 / 47.05,68024.57,653,2981,2601,51583%78995682%
                     
(1) Excludes non-operated wells and "shallow" wells, defined as wells whose vertical depth, including the "curve," is 10,500 feet or less.
(2) Wellhead rates only; the natural gas associated with these wells is yielding between 135 and 155 barrels of NGLs per million cubic feet.
(3) 30-day information for the Wombat #1H -- #4H wells or the Bock #1H -- #7H wells (11 wells in total) is not yet available. Includes information for the Cinco Ranch LTD Unit #1H well, which was brought on line in July 2014.
(4) Does not include the Fojtik #1H (Upper Eagle Ford well brought on line in March 2013).


Since our last quarterly report, we have turned in line 25 (15.2 net) operated wells (excludes shallow wells). As a group, these 25 wells had an average IP rate of 1,514 BOEPD over an average of 25.4 frac stages, with 81 percent of production from crude oil. Of these 25 wells, 15 wells with sufficient production history had a 30-day average rate of 948 BOEPD, with 77 percent of production from crude oil. In the first quarter, the average IP rate was 1,457 BOEPD over an average of 25.2 frac stages, with 80 percent of production from crude oil. Among the recent wells, the wells with the highest IP rates included the Bock #7H (3,175 BOEPD, a company record, over 26 frac stages), the Cinco Ranch LTD Unit #1H (2,611 BOEPD over 32 frac stages), the Bock #6H (2,272 BOEPD over 26 frac stages), the Amber #1H (2,217 BOEPD over 23 frac stages), the Amber #2H (1,919 BOEPD over 22 frac stages) and the Wombat #1H (1,670 BOEPD over 20 frac stages).   

The strong performances of these recent wells was attributable primarily to contributions from wells located in the "beer quad" area near Shiner, the Peach Creek area and the Rock Creek Ranch / Bozka areas. In addition, the amount of proppant per stage increased from an average of 311,000 pounds in the first quarter of 2014 to an average of 370,000 pounds in the second quarter. Costs per stage, on the other hand, decreased from $411,000 in the first quarter of 2014 to $373,000 in the second quarter.

Upper Eagle Ford (Marl) Shale Update

To date, we have tested three Upper Eagle Ford (Marl) Shale wells (Fojtik #1H, Welhausen #A2H and Martinsen #2H) and for the remainder of 2014 we have 19 additional Upper Eagle Ford wells planned to spud, with eight of those scheduled as development wells in the Welhausen area. 

The Welhausen #A2H was turned in line in March 2014 and has averaged 1,070 BOEPD over 95 days, 1,519 BOEPD over its first 60 days, 1,767 BOEPD over its first 30 days and had an IP rate of 2,165 BOEPD, with an oil and NGL percentage of approximately 70 percent. The Martinsen #2H was turned in line in May 2014 and has averaged 1,149 BOEPD over its first 60 days, 1,238 BOEPD over its first 30 days and had an IP rate of 1,360 BOEPD, with an oil and NGL percentage of approximately 74 percent.

After observing the performance of these wells relative to adjacent wells in the Lower Eagle Ford, we have increasing confidence that, at least in these areas, the Upper Eagle Ford and Lower Eagle Ford are separate reservoirs. During the second half of 2014, we will continue to test the Upper Eagle Ford across other portions of our Lavaca County acreage, with 11 additional wells planned to be spud in these other areas and all of those associated with pad drilling. 

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.

Second Quarter 2014 Conference Call

A conference call and webcast, during which management will discuss second quarter 2014 financial and operational results, is scheduled for Thursday, July 31, 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 3711735), 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 3711735. 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 oil and gas companies; our ability to successfully monetize select assets and repay our debt; leasehold terms expiring before production can be established; environmental obligations, costs and 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; compliance with and 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 Six months ended
 June 30,March 31,June 30,
  2014 2013 2014 2014 2013
Revenues          
Crude oil  $ 112,090  $ 86,867  $ 105,576  $ 217,666  $ 149,925
Natural gas liquids (NGLs)  8,037  7,313  9,373  17,410  14,440
Natural gas  16,302  15,554  18,203  34,505  27,593
Total product revenues  136,429  109,734  133,152  269,581  191,958
(Loss) gain on sales of property and equipment, net  (51)  256  56,826  56,775  (293)
Other  2,983  (335)  (113)  2,870  1,188
Total revenues  139,361  109,655  189,865  329,226  192,853
Operating expenses          
Lease operating  12,403  8,629  10,404  22,807  16,434
Gathering, processing and transportation  3,526  2,980  2,961  6,487  6,559
Production and ad valorem taxes  7,510  6,976  7,305  14,815  12,935
General and administrative (excluding equity-classified share-based compensation) (a)  14,014  12,970  15,863  29,877  22,828
Total direct operating expenses  37,453  31,555  36,533  73,986  58,756
Share-based compensation - equity classified awards (b)  826  2,686  825  1,651  3,771
Exploration   3,373  7,845  8,636  12,009  14,140
Depreciation, depletion and amortization  71,437  64,329  72,187  143,624  115,905
Impairment  117,908  --  --  117,908  --
Total operating expenses  230,997  106,415  118,181  349,178  192,572
           
Operating income (loss)  (91,636)  3,240  71,684  (19,952)  281
           
Other income (expense)          
Interest expense   (23,229)  (21,808)  (22,534)  (45,763)  (36,287)
Loss on extinguishment of debt  --  (29,157)  --  --  (29,157)
Derivatives  (42,665)  8,588  (15,662)  (58,327)  827
Other  30  17  1  31  44
           
Income (loss) before income taxes   (157,500)  (39,120)  33,489  (124,011)  (64,292)
Income tax (expense) benefit  56,716  13,682  (14,264)  42,452  22,471
Net income (loss)  (100,784)  (25,438)  19,225  (81,559)  (41,821)
Preferred stock dividends  (1,718)  (1,725)  (1,722)  (3,440)  (3,450)
Induced conversion of preferred stock  (3,368)  --  --  (3,368)  --
           
Net income (loss) attributable to common shareholders  $ (105,870)  $ (27,163)  $ 17,503  $ (88,367)  $ (45,271)
           
Net income (loss) per share:          
Basic  $ (1.59)  $ (0.43)  $ 0.27  $ (1.34)  $ (0.77)
Diluted  $ (1.59)  $ (0.43)  $ 0.22  $ (1.34)  $ (0.77)
           
Weighted average shares outstanding, basic   66,514  62,899  65,611  66,065  59,141
Weighted average shares outstanding, diluted  66,514  62,899  85,744  66,065  59,141
 
           
  Three months ended Three months ended Six months ended
 June 30,March 31,June 30,
  2014 2013 2014 2014 2013
Production          
Crude oil (MBbls)  1,119  858  1,076  2,195  1,457
NGLs (MBbls)  261  260  227  488  494
Natural gas (MMcf)  3,618  3,778  3,593  7,211  7,342
Total crude oil, NGL and natural gas production (MBOE)  1,983  1,748  1,902  3,885  3,175
           
Prices          
Crude oil ($ per Bbl)  $ 100.16  $ 101.23  $ 98.12  $ 99.16  $ 102.89
NGLs ($ per Bbl)  $ 30.85  $ 28.10  $ 41.27  $ 35.71  $ 29.21
Natural gas ($ per Mcf)  $ 4.51  $ 4.12  $ 5.07  $ 4.78  $ 3.76
           
Prices - Adjusted for derivative settlements          
Crude oil ($ per Bbl)  $ 94.72  $ 104.10  $ 96.00  $ 95.35  $ 106.52
NGLs ($ per Bbl)  $ 30.85  $ 28.10  $ 41.27  $ 35.71  $ 29.21
Natural gas ($ per Mcf)  $ 4.20  $ 4.06  $ 4.85  $ 4.51  $ 3.83
           
(a) Includes liability-classified share-based compensation expense attributable to our performance-based restricted stock units, which is payable in cash upon the achievement of certain market-based performance metrics. A total of $1.0 million and $0.4 million and $7.0 million and $0.5 million attributable to these awards is included in the three and six months ended June 30, 2014 and 2013, respectively.
(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 
       June 30,December 31,
        2014 2013
Assets          
Current assets      $336,873$233,696
Net property and equipment        2,217,954  2,237,304
Other assets        32,853  36,087
Total assets      $2,587,680$2,507,087
           
Liabilities and shareholders' equity          
Current liabilities      $284,552$258,145
Revolving credit facility        55,000  206,000
Senior notes due 2019        300,000  300,000
Senior notes due 2020        775,000  775,000
Other liabilities and deferred income taxes        156,736  179,138
Total shareholders' equity        1,016,392  788,804
Total liabilities and shareholders' equity      $2,587,680$2,507,087
         
           
           
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - unaudited
(in thousands)
           
  Three months ended Three months ended Six months ended
 June 30,March 31,June 30,
  2014 2013 2014 2014 2013
Cash flows from operating activities          
Net income (loss)  $(100,784)$(25,438)$19,225  $(81,559)  $(41,821)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:        
Loss on extinguishment of debt  --  29,157  --  --  29,157
Depreciation, depletion and amortization  71,437  64,329  72,187  143,624  115,905
Accretion of firm transportation obligation  230  649  354  584  856
Impairment  117,908  --  --  117,908  --
Derivative contracts:          
Net losses (gains)  42,665  (8,588)  15,662  58,327  (827)
Cash settlements, net  (7,222)  2,233  (3,057)  (10,279)  5,790
Deferred income tax expense (benefit)  (56,516)  (13,682)  14,064  (42,452)  (22,471)
(Gain) loss on sales of assets, net  51  (256)  (56,826)  (56,775)  293
Non-cash exploration expense  3,285  5,146  3,294  6,579  10,408
Non-cash interest expense  1,039  939  1,012  2,051  1,885
Share-based compensation (equity-classified)  826  2,686  825  1,651  3,771
Other, net  75  1  206  281  82
Changes in operating assets and liabilities  (40,361)  26,960  (386)  (40,747)  26,723
Net cash provided by operating activities  32,633  84,136  66,560  99,193  129,751
Cash flows from investing activities          
Acquisition, net  --  (358,239)  --  --  (358,239)
Payments to settle obligations assumed in acquisition, net  --  (36,310)  --  --  (36,310)
Capital expenditures - property and equipment  (190,776)  (143,346)  (159,804)  (350,580)  (229,319)
Proceeds from sales of assets, net  668  (11)  95,964  96,632  867
Net cash used in investing activities  (190,108)  (537,906)  (63,840)  (253,948)  (623,001)
Cash flows from financing activities          
Proceeds from the issuance of preferred stock, net  313,646  --  --  313,646  --
Payments made to induce conversion of preferred stock  (3,368)  --  --  (3,368)  --
Proceeds from the issuance of senior notes   --  775,000  --  --  775,000
Retirement of senior notes  --  (319,090)  --  --  (319,090)
Proceeds from revolving credit facility borrowings  217,000  115,000  85,000  302,000  153,000
Repayment of revolving credit facility borrowings  (352,000)  (86,000)  (101,000)  (453,000)  (86,000)
Debt issuance costs paid  (151)  (24,698)  --  (151)  (24,698)
Dividends paid on preferred and common stock  (2,111)  (1,725)  (1,725)  (3,836)  (3,412)
Other, net  --  (49)  1,085  1,085  (110)
Net cash provided by (used in) financing activities  173,016  458,438  (16,640)  156,376  494,690
Net increase (decrease) in cash and cash equivalents  15,541  4,668  (13,920)  1,621  1,440
Cash and cash equivalents - beginning of period  9,554  14,422  23,474  23,474  17,650
Cash and cash equivalents - end of period$25,095$19,090$9,554$25,095$19,090
           
Supplemental disclosures of cash paid for:          
Interest$46,009$22,876$1,025$47,034$23,215
Income taxes (net of refunds received)$100 $ -- $ --$100 $ --
 
PENN VIRGINIA CORPORATION
CERTAIN NON-GAAP FINANCIAL MEASURES - unaudited
(in thousands)
           
           
  Three months ended Three months ended Six months ended
 June 30,March 31,June 30,
  2014 2013 2014 2014 2013
Reconciliation of GAAP "Net income (loss) " to Non-GAAP "Net income (loss) applicable to common shareholders, as adjusted"          
Net income (loss)  $ (100,784)  $ (25,438)  $ 19,225  $ (81,559)  $ (41,821)
Adjustments for derivatives:          
Net losses (gains)  42,665  (8,588)  15,662  58,327  (827)
Cash settlements, net  (7,222)  2,233  (3,057)  (10,279)  5,790
Adjustment for acquisition transaction expenses  --   2,396  --   --   2,396
Adjustment for impairments   117,908  --   --   117,908  -- 
Adjustment for restructuring costs  (3)  --   12  9  -- 
Adjustment for (gain) loss on sale of assets, net  51  (256)  (56,826)  (56,775)  293
Adjustment for loss on extinguishment of debt  --   29,157  --   --   29,157
Impact of adjustments on income taxes  (55,239)  (8,723)  18,830  (37,378)  (12,865)
Preferred stock dividends  (1,718)  (1,725)  (1,722)  (3,440)  (3,450)
Net loss applicable to common shareholders, as adjusted (a)  $ (4,342)  $ (10,944)  $ (7,876)  $ (13,187)  $ (21,327)
           
Net loss applicable to common shareholders, as adjusted, per share, diluted   $ (0.07)  $ (0.17)  $ (0.12)  $ (0.20)  $ (0.36)
           
Reconciliation of GAAP "Net income (loss)" to Non-GAAP "Adjusted EBITDAX"          
Net income (loss)  $ (100,784)  $ (25,438)  $ 19,225  $ (81,559)  $ (41,821)
Income tax benefit  (56,716)  (13,682)  14,264  (42,452)  (22,471)
Interest expense  23,229  21,808  22,534  45,763  36,287
Depreciation, depletion and amortization  71,437  64,329  72,187  143,624  115,905
Exploration  3,373  7,845  8,636  12,009  14,140
Share-based compensation expense (equity-classified awards)  826  2,686  825  1,651  3,771
EBITDAX  (58,635)  57,548  137,671  79,036  105,811
Adjustments for derivatives:          
Net losses (gains)  42,665  (8,588)  15,662  58,327  (827)
Cash settlements, net  (7,222)  2,233  (3,057)  (10,279)  5,790
Adjustment for acquisition transaction expenses  --   2,396  --   --   2,396
Adjustment for impairments   117,908  --   --   117,908  -- 
Adjustment for (gain) loss on sale of assets, net  51  (256)  (56,826)  (56,775)  293
Adjustment for other non-cash items  230  647  354  584  854
Adjustment for loss on extinguishment of debt  --   29,157  --   --   29,157
Adjusted EBITDAX (b)  94,997  83,137  93,804  188,801  143,474
Pro forma EBITDAX from our 2013 Eagle Ford Shale acquisition   --   3,607  --   --   26,256
Pro forma Adjusted EBITDAX  $ 94,997  $ 86,744  $ 93,804  $ 188,801  $ 169,730
           
(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, impairments, 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 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 Second First      
  Quarter Quarter Half Full-Year
  2014 2014 2014 2014 Guidance
Production:            
Crude oil (MBbls) 1,076 1,119 2,195 5,300  --  5,550
NGLs (MBbls)  227 261 488 1,175  --  1,225
Natural gas (MMcf)  3,593 3,618 7,211 14,200  --  14,700
Equivalent production (MBOE) 1,902 1,983 3,885 8,842  --  9,225
Equivalent daily production (BOEPD) 21,133 21,786 21,461 24,224  --  25,274
Percent crude oil and NGLs 68.5% 69.6% 69.1% 72.5%  --  74.1%
             
Production revenues (a):            
Crude oil $105.6 112.1 217.7 485.0  --  520.0
NGLs $9.4 8.0 17.4 40.0  --  45.0
Natural gas$18.2 16.3 34.5 65.0  --  72.0
Total product revenues$133.2 136.4 269.6 590.0  --  637.0
Total product revenues ($ per BOE)$70.01 68.81 69.40 66.73  --  69.05
Percent crude oil and NGLs 86.3% 88.1% 87.2% 87.9%  --  89.7%
             
Operating expenses:            
 Lease operating ($ per BOE)$5.47 6.25 5.87 5.30  --  5.90
 Gathering, processing and transportation costs ($ per BOE)$1.56 1.78 1.67 1.80  --  2.05
 Production and ad valorem taxes (percent of oil and gas revenues) 5.5% 5.5% 5.5% 6.0%  --  7.0%
             
General and administrative:            
 Recurring general and administrative$9.7 11.8 21.5 42.5  --  44.0
 Non-recurring general and administrative$0.2 1.1 1.3 1.3  --  1.3
 Share-based compensation$6.8 1.9 8.6 12.0  --  15.0
Total reported G&A$16.7 14.8 31.5 55.8  --  60.3
             
Exploration:            
 Total reported exploration$8.6 3.4 12.0 22.0  --  24.0
 Unproved property amortization$3.3 3.4 6.7 13.0  --  13.5
             
Depreciation, depletion and amortization ($ per BOE)$37.95 36.03 36.97 36.00  --  37.00
             
Adjusted EBITDAX (b)$93.8 95.0 188.8 440.0  --  485.0
             
Capital expenditures:            
Drilling and completion$135.5 154.0 289.5 640.0  --  665.0
Lease acquisitions$36.9 12.8 49.7 97.0  --  115.0
Seismic (c)$4.5 0.1 4.6 8.0  --  9.0
Pipeline, gathering, facilities and other$5.6 2.6 8.2 17.0  --  19.0
 Total capital expenditures$182.4 169.5 351.9 762.0  --  808.0
             
End of period debt outstanding$1,265.0 1,130.0 1,130.0 1,075.0  --  1,140.0
Interest expense:            
 Total reported interest expense$22.5 23.2 45.8 91.0  --  94.0
 Cash interest expense$21.5 22.2 43.7 86.0  --  91.0
Preferred stock dividends paid$1.7 2.1 3.8 16.3  --  16.3
Income tax benefit rate  42.6% 36.0% 34.2% 36.5%  --  38.5%
             
(a) Assumes average benchmark prices of $90.00 per barrel for crude oil and $4.50 per MMBtu for natural gas in the second half 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 second half 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)  
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)  
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
Third quarter 2014 Swaps (a) 10,000 93.21  
Fourth quarter 2014 Swaps (a) 11,000 93.45  
First quarter 2015 Swaps (a) 9,000 91.81  
Second quarter 2015 Swaps (a) 9,000 91.81  
Third quarter 2015 Swaps (a) 7,000 91.09  
Fourth quarter 2015 Swaps (a) 7,000 91.09  
First quarter 2016 Swaps 3,000 90.84  
Second quarter 2016 Swaps 3,000 90.84  
Third quarter 2016 Swaps 3,000 90.84  
Fourth quarter 2016 Swaps 3,000 90.84  
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 second half of 2014 would increase or decrease by approximately $39.1 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 second half of 2014 would increase or decrease by approximately $7.9 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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