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Penn Virginia Corporation Announces Fourth Quarter And Full-Year 2012 Results; Provides Initial 2013 Guidance

Impairment expense increased to $75.2 million in the fourth quarter of 2012 from $0.7 million in the third quarter due to the write-down of our Marcellus Shale assets, primarily as a result of lower year-end gas prices and the resultant reduction in proved reserves.

Capital Expenditures

During the fourth quarter of 2012, oil and gas capital expenditures were approximately $118 million, compared to $85 million in the third quarter, consisting of:
  • $100 million for drilling and completion activities
  • $5 million for seismic, pipeline, gathering and facilities
  • $13 million for leasehold acquisitions, field projects and other

Capital expenditures during 2012 were approximately $384 million, approximately $34 million higher than the upper end of previous guidance. The increase was attributable to:
  • an additional 38 percent working interest in six Lavaca County Eagle Ford Shale wells
  • increased costs on recent Eagle Ford Shale wells due to operational issues
  • an acceleration into 2012 of certain 2013 drilling and completion expenditures, along with related pipeline expansion costs
  • additional Eagle Ford Shale lease acquisition costs
  • a vertical core test of the Pearsall Shale

As previously disclosed, we added approximately 18.3 MMBOE of proved reserves during 2012, prior to negative revisions of 28.7 MMBOE due primarily to benchmark natural gas prices in 2012 which were 33 percent lower than in 2011. Reserve replacement cost per BOE, defined as capital expenditures divided by reserve additions, excluding revisions, was approximately $21 per BOE. During 2012, we replaced approximately 280 percent of production, excluding revisions.

2013 Guidance

2013 guidance assumes that our working interest in a majority of our 2013 Lavaca County Eagle Ford Shale wells averages approximately 94 percent. 2013 guidance highlights are as follows:
  • Production is expected to be approximately 5.7 to 6.2 MMBOE (34.0 to 37.0 billion cubic feet of natural gas equivalent), or approximately 15,500 to 16,900 BOEPD, compared to 2012 production of approximately 5.8 MMBOE, or 15,776 BOEPD, pro forma to exclude 0.7 MMBOE of production in 2012 from divested Appalachian assets.
    • Crude oil production is expected to increase by 23 to 37 percent over 2012 levels (a 12 to 24 percent increase in crude oil and NGLs combined). Crude oil and NGLs are expected to comprise approximately 60 to 65 percent of total production, compared to 48 percent during 2012.
    • Production during January 2013 was approximately 15,600 BOEPD, approximately 42 percent of which was crude oil and approximately 16 percent of which was NGLs.
  • Product revenues are expected to be approximately $330 to $364 million, compared to 2012 product revenues of $310 million, excluding the impact of any hedges.
    • Crude oil and NGL product revenues are expected to be approximately 87 percent of total product revenues, compared to 84 percent during 2012.
    • Approximately 58 percent of the midpoint of estimated crude oil production and 55 percent of the midpoint of estimated natural gas production are currently hedged.
    • Settlements of current commodity hedges are expected to result in cash receipts of approximately $13 million.
  • Adjusted EBITDAX, a non-GAAP measure, is expected to be approximately $235 to $280 million, compared to 2012 Adjusted EBITDAX of $248 million.
  • Capital expenditures are expected to be $360 to $400 million, compared to approximately $385 million of 2012 capital expenditures.
    • Approximately 88 percent of capital expenditures are expected to be allocated to the Eagle Ford Shale and approximately 91 percent to development activities.
    • 2013 capital expenditures include $310 to $345 million for drilling and completions, $28 to $30 million for lease acquisitions and $22 to $25 million for pipeline, gathering, seismic and facilities.

Please see the Guidance Table included in this release for guidance estimates for 2013. These estimates are meant to provide guidance only and are subject to revision as our operating environment changes.

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