Penn Virginia Corporation Announces Third Quarter 2012 Results; Provides Updates of Operations and Full-Year 2012 Guidance; Provides Preliminary 2013 Guidance

Penn Virginia Corporation (NYSE: PVA) today reported results for the
three months ended September 30, 2012, provided updates of operations
and full-year 2012 guidance and provided preliminary guidance for 2013.

Third Quarter 2012 Highlights

Third quarter 2012 results compared to the third quarter of 2011 were as
follows:

• 
  Oil and natural gas liquids (NGLs) production of 776 thousand barrels
  of oil (MBO), or 52 ?percent of total equivalent production, an
  increase of 19 ?percent compared to 649 MBO, or 33 ?percent of total
  equivalent production
  
• 
  Oil production of 573 MBO, an increase of 34 percent compared to 427
  MBO
  
• 
  Oil and NGL revenues of $63.7 million, or 84 percent of product
  revenues, an increase of 33 ?percent compared to $47.8 ?million, or 58
  percent of product revenues
  
• 
  Product revenues from the sale of natural gas, crude oil and NGLs of
  $75.6 million, or $8.37 ?per thousand cubic feet of natural gas
  equivalent (Mcfe), a decrease of eight percent compared to
  $82.0 ?million, or $6.86 per Mcfe (22 percent increase in per unit
  revenues) due to lower gas prices and divestitures of natural gas
  properties
  
• 
  Gross operating margin, a non-GAAP (generally accepted accounting
  principles) measure defined as total product revenues less total
  direct operating expenses, of $5.68 per Mcfe, an increase of 20
  percent compared to $4.72 per Mcfe
  
• 
  Adjusted EBITDAX, a non-GAAP measure, of $61.2 million, a decrease of
  eight percent compared to $66.3 million due to lower gas prices and
  production, lower NGL prices and the receipt of $2.9 million in the
  prior year period related to the termination of an interest rate swap,
  partially offset by higher oil prices and production
  
• 
  Operating loss of $24.5 ?million, including $17.3 million of charges
  related to firm transportation commitments in Appalachia, compared to
  a loss of $9.0 million
  
• 
  Net loss of $32.6 million, or $0.71 per diluted share, compared to a
  loss of $6.7 ?million, or $0.15 per diluted share
  
• 
  Adjusted net loss, a non-GAAP measure which excludes the effects of
  changes in derivatives fair value, impairments, restructuring costs
  and other gains or losses that affect comparability to the prior year
  period, of $7.3 ?million, or $0.16 per diluted share, compared to a
  loss of $6.7 million, or $0.15 per diluted share
  

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

Recent Eagle Ford operational highlights are as follows:

• 
  We have completed eight (6.7 net) Eagle Ford Shale wells and acquired
  one (1.0 net) Eagle Ford Shale well since early August. This brings
  the total number of on-line wells to 59 ?(49.1 ?net), with one (0.9 net)
  well being completed and the 61^st through 63^rd
  wells being drilled
  
  
  • 
    The average peak gross production rate per well for the 49 wells
    we completed with full-length laterals was 986 ?barrels of oil
    equivalent (BOE) per day (BOEPD)
    
  • 
    The initial 30-day average gross production rate for the 45 of
    these 49 wells with a 30-day production history was 656 ?BOEPD
    
  • 
    Eagle Ford Shale oil production will begin to increase late in
    2012 with the recent addition of a third drilling rig
    
• 
  Our Eagle Ford Shale net production was approximately 6,300 BOEPD
  during the third quarter of 2012, with oil comprising approximately
  84 ?percent, NGLs approximately nine percent and natural gas
  approximately seven ?percent
  
• 
  The results of seven wells drilled and completed to date in Lavaca
  County continue to meet our expectations with an average initial
  production of 829 BOEPD and significant back pressures, as well as
  30-day average rates for five of these wells of 678 BOEPD, which
  exceeds our 30-day average in Gonzales County
  
• 
  As previously disclosed, we have increased our Eagle Ford Shale
  acreage position in Gonzales and Lavaca Counties, Texas to
  approximately 40,000 gross (30,000 net) acres with up to approximately
  285 remaining drilling locations
  

Management Comment

H. Baird Whitehead, President and Chief Executive Officer stated, 'Our
third quarter results met our expectations, with Adjusted EBITDAX at or
above $60 million for the fifth consecutive quarter. We believe our cash
operating margin per unit of production is among the best of our small
cap peers. We have had excellent well results in the Eagle Ford Shale
and are pleased with our recent Eagle Ford Shale acreage additions and
increases to our drilling inventory. The recent addition of the third
rig in the Eagle Ford Shale play will allow us to resume sequential
crude oil as well as overall production growth, on a pro forma basis, as
we enter 2013. Recent acreage additions and derisking of our Lavaca
County, Texas acreage now provide a greater than six-year inventory of
drilling locations for a three-rig program.

'Since July 31^st, we have sold our Appalachian assets,
completed concurrent offerings of $161 million of preferred and common
equity and received a $32 million federal income tax refund,
significantly improving the strength of our balance sheet and financial
liquidity. As a result, we are well positioned to fund our 2013 Eagle
Ford Shale drilling program, on which we will continue to be focused.?

Third Quarter 2012 Financial and Operational Results

Pricing

Our third quarter 2012 realized oil price of $99.45 per barrel was 14
percent higher than the $87.03 ?per barrel price in the prior year
quarter. Our third quarter 2012 realized NGL price of $32.94 per barrel
was 31 ?percent lower than the $48.00 ?per barrel price in the prior year
quarter. Our third quarter 2012 realized natural gas price of $2.72 per
thousand cubic feet (Mcf) was 36 percent lower than the $4.24 per Mcf
price in the prior year quarter. Adjusting for oil and gas hedges, our
third quarter 2012 effective oil price was $107.53 ?per barrel, and our
effective natural gas price was $3.77 ?per Mcf, or increases of $8.08 per
barrel and $1.05 per Mcf over the realized prices.

Overview of Financial Results

The operating loss in the third quarter of 2012 was $24.5 million,
compared to the $9.0 ?million loss in the prior year quarter. The
increase in loss of $15.5 million was due primarily to a $17.3 million
increase in charges during the third quarter of 2012 related to firm
transportation commitments for divested Appalachian assets and a $5.7
million decrease in total revenues, partially offset by a $7.5 ?million
decrease in other operating expenses. Oil and NGL revenues were
$63.7 ?million in the third quarter of 2012, 33 ?percent higher than the
$47.8 ?million in the prior year quarter. Oil and NGL revenues were
84 ?percent of product revenues in the third quarter of 2012, compared to
58 percent in the prior year quarter.

Production

As shown in the table below, production in the third quarter of 2012 was
9.0 Bcfe, or 98.1 ?MMcfe per day, a 24 ?percent decrease compared to 11.9
Bcfe, or 129.9 MMcfe per day, in the prior year quarter. Excluding
production from the Appalachian assets sold in July 2012 and the Arkoma
Basin assets sold in August 2011, production in the third quarter of
2012 was 8.3 Bcfe, or 90.5 MMcfe per day, and the production in the
prior year quarter was 9.2 ?Bcfe, or 100.0 MMcfe per day. The 0.9 Bcfe,
or nine percent, decrease in pro forma production was the result of a
1.6 ?Bcfe, or 31 percent, decrease in natural gas production due to
reduced natural gas drilling since mid-2010, partially offset by a 127
MBO (0.8 ?Bcfe), or 20 percent, increase in oil and NGL production due
primarily to drilling in the Eagle Ford Shale since early 2011. As a
percentage of total equivalent production, oil and NGL volumes were
52 ?percent in the third quarter of 2012 compared to 33 ?percent in the
prior year quarter. Oil production increased 34 percent from 427 ?MBO in
the prior year quarter to 573 MBO in the third quarter of 2012.

Operating Expenses

Third quarter 2012 total direct operating expenses decreased $1.3
million, or approximately five ?percent, to $24.3 ?million, or $2.69 ?per
Mcfe produced, compared to $25.6 million, or $2.14 per Mcfe produced, in
the prior year quarter.

• 
  Lease operating expenses decreased by $2.3 million, or 27 percent, to
  $6.2 million, or $0.69 ?per Mcfe produced, from $8.5 million, or $0.71
  per Mcfe produced, due primarily to lower repair and maintenance,
  compression and water disposal expenses, as well as reduced expenses
  attributable to the sale of our Appalachian properties in July 2012
  and our Arkoma Basin properties in August 2011. These cost decreases
  were partially offset by higher chemical treatment and environmental
  compliance costs attributable to our expanded oil drilling program.
  
• 
  Gathering, processing and transportation expenses increased by
  approximately $0.1 million, or six percent, to $3.1 ?million, or $0.35
  per Mcfe produced, from $3.0 million, or $0.25 per Mcfe produced, due
  primarily to higher processing costs associated with NGLs in the 2012
  period.
  
• 
  Production and ad valorem taxes increased $1.2 million, or 35 percent,
  to $4.6 ?million, or 6.1 percent of total product revenues, from
  $3.4 ?million, or 4.1 percent of total product revenues, because we
  reported a property tax recovery of $1.2 million attributable to wells
  in West Virginia during the 2011 period.
  
• 
  General and administrative (G&A) expense, excluding share-based
  compensation, decreased by approximately $0.4 ?million, or
  four ?percent, to $10.4 ?million, or $1.15 per Mcfe produced, from $10.8
  million, or $0.91 per Mcfe produced. Excluding restructuring costs in
  the third quarters of both 2012 and 2011 related to the Appalachian
  and Arkoma asset sales, G&A expense, excluding share-based
  compensation, decreased by approximately $0.4 ?million, or four
  percent, to $8.9 ?million, or $0.99 per Mcfe produced, from $9.3
  million, or $0.78 per Mcfe produced. This decrease was due primarily
  to lower employee headcount and lower support costs following
  restructuring actions taken during 2011 and 2012, with the unit cost
  increasing due to lower gas equivalent production volumes.
  

Exploration expense decreased $10.0 million, or 52 percent, to
$9.3 ?million in the third quarter of 2012 from $19.3 ?million in the
prior year quarter. The decrease was due primarily to a $2.7 ?million
decrease in unproved property amortization, a $2.8 million decrease in
geological and geophysical costs and a 2011 charge of $4.8 million for a
contract termination.

Depreciation, depletion and amortization (DD&A) expense increased by
$4.0 million, or nine percent, to $49.3 ?million, or $5.47 per Mcfe
produced, in the third quarter of 2012 from $45.3 million, or $3.80 per
Mcfe produced, in the prior year quarter, due primarily to higher DD&A
costs attributable to our Eagle Ford Shale oil wells and reserve
revisions associated with our gas assets.

Capital Expenditures

During the third quarter of 2012, capital expenditures were
approximately $85 million, compared to $114 ?million in the prior year
quarter, consisting of:

• 
  $73 million for drilling and completion activities
  
• 
  $5 million for pipeline, gathering, facilities and seismic
  
• 
  $6 million for leasehold acquisitions and other
  

Comparison of Third Quarter of 2012 to Second Quarter of 2012

As shown in the table above, production in the third quarter of 2012 of
approximately 9.0 Bcfe, or 98.1 MMcfe per day, was 1.7 ?Bcfe, or 19.0
MMcfe per day, less than in the second quarter of 2012 due primarily to
a 1.5 Bcfe decline in natural gas production as a result of the
Appalachian sale and natural declines, as well as lower NGL production
in the Mid-Continent associated with ethane rejection and reduced
natural gas production. Crude oil production was essentially flat on a
sequential basis as a result of the reduction in the rig count in the
Eagle Ford Shale from three rigs to two rigs earlier in the year. We
expect crude oil production to decrease slightly for the fourth quarter,
after which we expect oil production to begin increasing in the first
quarter of 2013 due to contributions associated with the third rig.
During the third quarter of 2012, total product revenues were flat at
approximately $76 million compared to the prior quarter as the decline
in total production was offset by higher realized oil and gas prices.
Due to flat sequential direct operating expenses of approximately $24
million in both quarters, increased cash settlements of derivatives in
the third quarter and despite the sale of Appalachia at the end of July,
third quarter Adjusted EBITDAX of approximately $61 ?million was slightly
higher than the approximately $60 million in the prior quarter.

Operational Update

Eagle Ford Shale

During the third quarter of 2012, we drilled six (5.0 net) operated
wells in the Eagle Ford Shale, all of which were successful. Since early
August, we have completed eight (6.7 net) Eagle Ford Shale wells and
acquired one (1.0 net) Eagle Ford Shale well, bringing the total to 59
(49.1 net) producing wells, with one (0.9 net) well being completed and
the 61^st through 63^rd wells being drilled. The
average peak gross production rate per well for the 49 wells we
completed with full-length laterals was 986 ?BOEPD. The initial 30-day
average gross production rate for 45 of these 49 wells with a 30-day
production history was 656 ?BOEPD. Our Eagle Ford Shale production was
approximately 6,300 net BOEPD during the third quarter of 2012, with oil
comprising approximately 84 ?percent, NGLs approximately nine percent and
natural gas approximately seven percent.

Progress continues in reducing our drilling and completion costs. By
sourcing our guar and proppant directly, we have stabilized our drilling
and completion costs at $7.0 to $8.0 million per well in Gonzales County
and, going forward, $8.5 to $9.5 million per well in Lavaca County, both
depending on lateral length. We are also using only 100 percent
high-strength white sand for proppant in Gonzales County and recently
initiated the use of a mix of ceramic and high-strength white sand in
Lavaca County.

Our full-year 2012 guidance anticipates the drilling of 33 ?(26.3 ?net)
wells in the Eagle Ford Shale, including the wells drilled during the
first nine months of 2012. As previously disclosed, we have increased
our Eagle Ford Shale acreage position to approximately 40,000 gross
(30,000 net) acres with a drilling inventory of up to approximately 285
locations. Efforts continue to expand our Eagle Ford Shale position
through additional leasing and selective acquisitions.

Mid-Continent

During the third quarter of 2012, we drilled four (1.1 net) non-operated
wells in the Granite Wash; one (0.5 net) well was successful, with final
results not yet established on three (0.6 net) wells. We experienced
operational problems while drilling our first horizontal Viola Lime well
in Jefferson County, Oklahoma and, as a result, shortened the well′s
planned lateral length by approximately 3,000 feet. We concluded that
the drilled lateral length of approximately 1,100 feet was sufficient to
test the concept of the prospect and we stimulated the shortened lateral
with a seven-stage acid frac. The production rate is less than 10 BOPD,
on pump, which is much less than anticipated. The prospect is being
re-evaluated with the possibility of drilling an additional well in 2013
or attempting a recompletion in an up-hole interval in the existing
well. We have an acreage position of approximately 9,600 net acres in
this play.

Full-Year 2012 Guidance

Full-year 2012 guidance highlights are as follows:

• 
  Full-year 2012 production of approximately 38 to 39 Bcfe (7.9 to 8.3
  Bcfe in the fourth quarter of 2012), compared to previous guidance of
  37 to 40 ?Bcfe
  
  
  • 
    Crude oil and NGLs are expected to comprise approximately
    48 ?percent of total production during 2012, compared to previous
    guidance of approximately 47 percent (approximately 54 percent
    during the fourth quarter of 2012)
    
• 
  Full-year 2012 product revenues are expected to be approximately $301
  to $307 million ($66 to $73 million in the fourth quarter of 2012),
  compared to previous guidance of $284 to $303 million, excluding the
  impact of our hedges
  
  
  • 
    Crude oil and NGL product revenues are expected to be
    approximately 84 percent of total product revenues, unchanged from
    previous guidance
    
  • 
    Full-year 2012 settlements of current commodity hedges are
    expected to result in cash receipts of approximately $30 ?million,
    $24 million of which was received during the first nine months of
    2012
    
• 
  Full-year 2012 Adjusted EBITDAX, a non-GAAP measure, is expected to be
  $235 to $245 million ($50 to $60 million in the fourth quarter of
  2012), compared to previous guidance of $225 to $245 million
  
• 
  Full-year 2012 capital expenditures are expected to be $338 to
  $350 ?million ($71 to $83 million in the fourth quarter of 2012),
  compared to $300 to $325 ?million of previous guidance, due to
  increased working interests in recent Lavaca County Eagle Ford Shale
  wells as a result of our partner going non-consent, as well as
  announced acreage additions in the Eagle Ford Shale during the third
  quarter of 2012
  
  
  • 
    Approximately 90 percent of 2012 capital expenditures are expected
    to be allocated to the Eagle Ford Shale, approximately six percent
    to the Mid-Continent and four percent to other areas
    

Please see the Guidance Table included in this release for guidance
estimates for full-year 2012. These estimates are meant to provide
guidance only and are subject to revision as our operating environment
changes.

Preliminary Full-Year 2013 Guidance

As a result of recent equity offerings, the sale of our Appalachian
assets and the receipt of a federal income tax refund, we expect to have
over $300 ?million of available liquidity in the form of cash and
equivalents and revolver availability as we enter 2013. Preliminarily,
we estimate 2013 capital expenditures will range between $310 and $345
million, compared to the mid-point of 2012 capital expenditures guidance
of $343 million. This range is contingent on our partner in Lavaca
County participating in applicable Lavaca County wells that we plan to
drill. During 2013, approximately 85 ?percent of our capital expenditures
will be allocated to activity in Gonzales and Lavaca Counties.
Preliminarily, full-year 2013 production is estimated to be
approximately 34 to 37 Bcfe, compared to the mid-point of 2012
production guidance, pro forma for the sale of our Appalachian assets,
of approximately 34 Bcfe. We estimate that 2013 oil and NGL production
will range between 55 and 65 percent of total production. Full year
crude oil production is expected to be approximately 25 percent higher
in 2013 than the midpoint of 2012 production guidance, while fourth
quarter 2013 oil production is expected to be approximately 40 percent
higher than the midpoint of fourth quarter 2012 oil production guidance.
Our expected cash flows in 2013, along with available liquidity as we
enter 2013, are expected to be more than sufficient to fund 2013 capital
expenditures.

Capital Resources and Liquidity

As of September 30, 2012, we had total debt with a carrying value of
approximately $676 million ($682 million aggregate principal amount),
consisting of $294 million of 10.375 percent senior unsecured notes due
2016 ($300 million principal amount), $300 million principal amount of
7.25 ?percent senior unsecured notes due 2019, approximately $5 ?million
principal amount of 4.5 ?percent convertible senior subordinated notes
due in November 2012 (classified as a current liability) and $77 million
of borrowings under our revolving credit facility (Revolver). Our
indebtedness at September 30, 2012 was approximately 46 ?percent of book
capitalization and 2.7 times the latest twelve months′ Adjusted EBITDAX
of $248 ?million. As a result of the $161 million issuance of preferred
and common equity in October 2012, pro forma net debt at September 30,
2012 was approximately $516 million and net debt-to-Adjusted EBITDAX was
approximately 2.1 ?times. Currently, we have no amounts borrowed under
the Revolver, approximately $298 million of availability under the
Revolver and approximately $50 million of cash on hand. We have no
material debt maturities until 2016.

Explanation of Non-GAAP Gross Operating Margin per Mcfe

Gross operating margin is a non-GAAP financial measure under Securities
and Exchange Commission (SEC) regulations which represents total product
revenues less total direct operating expenses. Gross operating margin
per Mcfe is equal to gross operating margin divided by total natural
gas, crude oil and NGL production. Gross operating margin is not
adjusted for the impact of hedges. We believe that gross operating
margin per Mcfe is an important measure that can be used by security
analysts and investors to evaluate our operating margin per unit of
production and to compare it to other oil and gas companies, as well as
for comparisons to other time periods.

Third Quarter 2012 Financial and Operational Results Conference Call

A conference call and webcast, during which management will discuss
third quarter 2012 financial and operational results, is scheduled for
Thursday, November 1, 2012 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 1-866-630-9986 five to 10 minutes before the
scheduled start of the conference call (use the passcode 4295337), 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 888-203-1112
(international: 719-457-0820) and using the replay code 4295337. 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 primarily in the development, exploration and production
of natural gas and oil in various domestic onshore regions including
Texas, Oklahoma, Mississippi and Pennsylvania.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 and natural gas; our
ability to develop, explore for, acquire and replace oil and 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, natural
gas liquids 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 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 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.

(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 $0.2 million and $0.8 million attributable to these
awards is included in the three and nine months ended September 30, 2012.

(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.

(a) The convertible notes are due in November 2012 and are included in
current liabilities.

(a) Net loss, as adjusted, represents the net loss adjusted to exclude
the effects of non-cash changes in the fair value of derivatives,
restructuring costs, and net gains and losses on the sale of assets. 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, 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.

(b) Adjusted EBITDAX represents net loss before income tax expense or
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, and net gains and losses on the sale of assets. 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. Adjusted EBITDAX represents
EBITDAX as defined in our revolving credit facility.