8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

Date of Report: August 25, 2014 (August 25, 2014)

(Date of Earliest Event Reported)

PENN VIRGINIA CORPORATION

(Exact Name of Registrant as Specified in its Charter)

Virginia	1-13283	23-1184320
(State or Other Jurisdiction of Incorporation)	(Commission File Number)	(IRS Employer Identification No.)
Four Radnor Corporate Center, Suite 200 100 Matsonford Road, Radnor, Pennsylvania		19087
(Address of Principal Executive Offices)		(Zip Code)

Registrant’s telephone number, including area code: (610) 687-8900

Not Applicable

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 2.02 Results of Operations and Financial Condition.

and

Item 7.01 Regulation FD Disclosure.

On August 25, 2014, Penn Virginia Corporation (“PVA”) issued a press release announcing updated guidance for the second half of 2014. A copy of the press release is furnished as Exhibit 99.1 to this Current Report on Form 8-K and is incorporated herein by reference. On the same date, PVA posted a new investor presentation on its web site. A copy of the investor presentation is furnished as Exhibit 99.2 to this Current Report on Form 8-K and is incorporated herein by reference.

The non-generally accepted accounting principles (“non-GAAP”) measure of Adjusted EBITDAX is presented in the Appendix to the investor presentation. The amounts included in the calculation of this measure are computed in accordance with generally accepted accounting principles (“GAAP”). As part of the information contained in the Appendix to the investor presentation, we have provided a reconciliation of this non-GAAP financial measure to its most comparable financial measure calculated and presented in accordance with GAAP. We believe that investors can more accurately understand our financial results if they have access to the same financial measures used by management.

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 2013 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.

In accordance with General Instruction B.2 of Form 8-K, the above information, the investor presentation and the press release are being furnished under Items 2.02 and 7.01 of Form 8-K and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, or otherwise subject to the liabilities of that section, nor shall such information and exhibits be incorporated by reference into any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934 except as shall be expressly set forth by specific reference in such a filing.

Item 9.01. Financial Statements and Exhibits.

(d) Exhibits.

99.1	Penn Virginia Corporation press release dated August 25, 2014.
99.2	Penn Virginia Corporation investor presentation dated August 2014.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

Date: August 25, 2014

Penn Virginia Corporation
By:	/s/ Steven A. Hartman
Name:	Steven A. Hartman
Title:	Senior Vice President and Chief Financial Officer

Exhibit Index

Exhibit No.	Description
99.1	Penn Virginia Corporation press release dated August 25, 2014.
99.2	Penn Virginia Corporation investor presentation dated August 2014.

EX-99.1

Exhibit 99.1

Four Radnor Corporate Center, Suite 200

Radnor, PA 19087

Ph: (610) 687-8900 Fax: (610) 687-3688

www.pennvirginia.com

FOR IMMEDIATE RELEASE

PENN VIRGINIA CORPORATION PROVIDES GUIDANCE UPDATE

Announces Participation in Upcoming Investor Conferences

RADNOR, PA (Globe Newswire) August 25, 2014 – Penn Virginia Corporation (NYSE: PVA) announced updated guidance for the second half of 2014. PVA also announced it has released a new investor presentation and its upcoming investor conference schedule.

Guidance Update

Although well results continue to meet or exceed expectations, we anticipate delays in the timing of completions associated with our second half of 2014 drilling program, including those wells to be drilled with the recently added seventh and eighth drilling rigs. In addition, as a result of the delays, we now expect four (2.5 net) fewer wells will be turned in line in 2014, with those four wells now expected to be turned in line during the first quarter of 2015.

During the second half of 2014, production is now expected to range between 23.4 and 25.5 thousand barrels of oil equivalent per day (MBOEPD), with production of 20.8 to 22.0 MBOEPD expected during the third quarter and 26.0 to 29.0 MBOEPD expected in the fourth quarter.

Pro forma for the sale of our Mississippi assets, which closed at the end of July, we now expect a one to seven percent increase in production in the third quarter over the second quarter and a 29 to 36 percent increase in production in the fourth quarter over the third quarter. Our Eagle Ford production is expected to increase approximately 50 to 60 percent in the second half of 2014 over the first half, driven by continued well completions and anticipated strong well results.

As a result of this reduced 2014 completion activity, second half 2014 capital expenditures are expected to range between $380 and $420 million. Adjusted EBITDAX, which includes the cash impact of derivatives, for the second half of 2014 is expected to range between $210 and $245 million. We anticipate having no outstanding borrowings under our revolving credit facility and financial liquidity of nearly $500 million at the end of the year.

These second half 2014 estimates are meant to provide guidance only and are subject to revision as our operating environment changes.

	Updated Guidance
	Three Months Ending		Six Months Ending
	Sept. 30, 2014	Dec. 31, 2014	Dec. 31, 2014
Oil production (MBO)	1,220 –1,285	1,465 – 1,630	2,685 – 2,915
NGL production (MBO)	255 – 270	370 – 415	625 – 685
Natural gas production (MMcf)	2,604 –2,814	3,342 – 3,738	5,946 – 6,552
Total production (MBOE)	1,909 – 2,024	2,392 – 2,668	4,301 – 4,692
Total production (BOEPD)	20,750 – 22,000	26,000 – 29,000	23,375 – 25,500
Gross / net well TILs			64/36.5
Adjusted EBITDAX ($MM)			$210 – $245
Capital expenditures ($MM)			$380 – $420

Note: MBO = thousand barrels of oil or natural gas liquids (NGL); MMcf = million cubic feet; MBOE = thousand barrels of oil equivalent; BOEPD = barrel of oil equivalent per day; TIL = turn-in line; $MM = million dollars; EOP = end of period.

Our preliminary estimate for 2015 total production is 35 to 45 percent higher than 2014, with oil production 45 to 60 percent higher than 2014. 2015 capital expenditures are expected to range between $750 and $800 million with adjusted EBITDAX that will be between 35 and 40 percent higher than 2014.

The preliminary estimates for full-year 2015 are meant to provide guidance only and are subject to revision as our 2015 budget is finalized.

New Investor Presentation and Upcoming Investor Conference Participations

Today, PVA posted a new investor presentation on its website at www.pennvirginia.com.

PVA also announced that it will present at Barclays Capital’s CEO Energy-Power Conference on Thursday, September 4, 2014 at 2:25 p.m. ET. H. Baird Whitehead, President and Chief Executive Officer, will present an overview of PVA’s operations, including a discussion of strategy and recent activities.

PVA will present at the 5^th Annual Credit Suisse Small & Mid Cap Conference on Tuesday, September 16, 2014 at 3:50 p.m. ET. Steven A. Hartman, Senior Vice President and Chief Financial Officer, will present an overview of PVA’s operations, including a discussion of strategy and recent activities.

PVA will present at the DUG Eagle Ford Conference and Exhibition, hosted by Hart Energy, in San Antonio on Wednesday, September 17, 2014 at 8:30 a.m. CT/9:30 a.m. ET). John A. Brooks, Executive Vice President and Chief Operating Officer, will present a detailed overview of PVA’s Eagle Ford Shale operations and recent activities.

PVA will present at the 8^th Annual Global Opportunities Conference, hosted by Imperial Capital, on Thursday, September 18, 2014. Mr. Hartman will present an overview of PVA’s operations, including a discussion of strategy and recent activities.

To view the new investor presentation as well as the accompanying slideshow presentation to be posted prior to the conferences, as well as to listen to the conference webcasts, please visit our website, www.pennvirginia.com under “Investor Relations—Events & Presentations.”

******

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, 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.

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

EX-99.2

Investor Presentation

August 25, 2014

NYSE: PVA

Exhibit 99.2

Forward-Looking Statements / Oil and Gas Reserves and Definitions

1

Forward-Looking Statements

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

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, changed circumstances or otherwise.

Oil and Gas Reserves

Effective

January

1,

2010,

the

SEC

permits

oil

and

gas

companies,

in

their

filings

with

the

SEC,

to

disclose

not

only

“proved”

reserves,

but

also

“probable”

reserves

and

“possible”

reserves.

As

noted

above,

statements

of

reserves

are

only

estimates

and

may

not

correspond

to

the

ultimate

quantities

of

oil

and

gas

recovered.

Investors

are

urged

to

consider

closely

the

disclosure

in

PVA’s

Annual

Report

on

Form

10-K

for

the

fiscal

year

ended

December

31,

2013,

which

is

available

from

PVA

at

Four

Radnor

Corporate

Center,

Suite

200,

Radnor,

PA

19087

(Attn:

Investor

Relations).

You

can

also

obtain

this

report

from

the

SEC

by

calling

1-800-SEC-0330

or

from

the

SEC’s website at www.sec.gov.

Definitions

Proved

reserves

are

those

quantities

of

oil

and

gas

which,

by

analysis

of

geosciences

and

engineering

data,

can

be

estimated

with

reasonable

certainty

to

be

economically

producible

from

a

given

date

forward,

from

known

reservoirs,

and

under

existing

economic

conditions,

operating

methods

and

government

regulation

before

the

time

at

which

contracts

providing

the

right

to

operate

expire,

unless

evidence

indicates

that

renewal

is

reasonably

certain,

regardless

of

whether

the

estimate

is

a

deterministic

estimate

or

probabilistic

estimate.

Probable

reserves

are

those

additional

reserves

that

are

less

certain

to

be

recovered

than

proved

reserves,

but

which

are

as

likely

than

not

to

be

recoverable

(there

should

be

at

least

a

50%

probability

that

the

quantities

actually

recovered

will

equal

or

exceed

the

proved

plus

probable

reserve

estimates).

Possible

reserves

are

those

additional

reserves

that

are

less

certain

to

be

recoverable

than

probable

reserves

(there

should

be

at

least

a

10%

probability

that

the

total

quantities

actually

recovered

will

equal

or

exceed

the

proved

plus

probable

plus

possible

reserve

estimates).

“3P”

reserves

refer

to

the

sum

of

proved,

probable

and

possible

reserves.

Estimated

ultimate

recovery

(EUR)

is

the

sum

of

reserves

remaining

as

of

a

given

date

and

cumulative

production

as

of

that

date.

EUR

is

a

measure

that

by

its

nature

is

more

speculative

than

estimates

of

reserves

prepared

in

accordance

with

SEC

definitions

and

guidelines

and

accordingly is less certain.

Reconciliation of GAAP and Non-GAAP Financial Measures

This

presentation

contains

references

to

both

GAAP

and

non-GAAP

financial

measures.

Reconciliations

between

GAAP

and

non-GAAP

financial

measures

are

available

in the appendix to this presentation.

2

•

Contiguous and high-quality acreage position in the Eagle

Ford

•

Approximately 101,800 net acres with over 1,600 potential identified drilling

locations; approximately 12-year drilling inventory  with 8 rigs

(1)

•

Continue to high-grade our drilling program and increase acreage footprint

•

Recent operational success

•

Strong Upper Eagle Ford results have confirmed stacked potential

and

significant upside

•

Excellent results in the Shiner “Beer Quad”

and Peach Creek areas

•

Significant

oil

focus

–

current

2014E

oil

production

growth

guidance of 42% to 49%

•

Experienced team manages aggressive growth strategy

•

Portfolio optimization focusing on Eagle Ford growth

•

YTD 2014 divestitures with gross proceeds of $319 MM

•

Recently announced Eagle Ford acreage acquisition for $45 MM

(1)

(1) Acreage and location data includes impact of Eagle Ford acquisition announced on 7/10/14 and expected to close in August 2014.

Penn Virginia Today

Eagle Ford Shale Will Drive Continued Growth

3

Granite Wash/Mid-Continent

Eagle Ford/South Texas

East Texas

Total Company

•

YE 2013 Proved Reserves

(1)

•

2Q 2014 Production

(1)

•

Eagle Ford Acreage & Locations

(2)

(1)

(2)

Acreage and location data includes impact of Eagle Ford acquisition announced on 7/10/14 and expected to close in August 2014.

Includes

14.2

MMBOE

of

proved

reserves

at

YE13

and

1.9

MBOEPD

of

2Q14

production

from

Mississippi

assets

sold

in

July

2014.

Operating Areas

As of and for the Quarter Ended June 30, 2014

•

~142,500 gross (~101,800 net)

•

Over 1,600 gross potential

identified drilling locations

•

7

rigs

drilling,

plan

to

add

8

th

in

3Q

2014

•

21.8 MBOEPD

•

56% Oil, 70% Liquids

•

3% growth over 1Q14

•

136.3 MMBOE

•

40% Developed

•

45% Oil, 61% Liquids

YE13 Proved Reserves: 75.6 MMBOE

29% Developed

2Q14 Production: 15.6 MBOEPD

YE13 Proved Reserves: 35.9 MMBOE

41% Developed

2Q14 Production: 2.4 MBOEPD

YE13 Proved Reserves: 10.6 MMBOE

80% Developed

2Q14 Production: 1.8 MBOEPD

Strategy

4

Focused on

Operational Execution

and Further

Expansion in the

Eagle Ford

•

Increasing

to

eight

drilling

rigs

in

3Q

2014,

107

(64.5

net)

TILs

in

2014

(1)

•

Goal: continue to increase acreage position in our “backyard”

•

Delivering high levels of production, reserve and EBITDAX growth

Focused on

Maintaining

Good  Liquidity

•

Recent offering, sale of assets, cash flow from operations and availability under our

revolver provide liquidity to fund our anticipated development program

•

Goal is to self-fund our capital program by 2017

•

Recent asset sales and arbitration award increased liquidity

Focused on

Generating New

Opportunities

•

Delineating

reserve

and

production

potential

of

Upper

Eagle

Ford

(Marl)

Shale

•

Continuing to evaluate new oil resource play opportunities that have early entry

possibilities

(1) Assumes 64 (36.5 net) TILs (turn-in lines) for the balance of 2014.

•

Selma

Chalk

assets

–

closed

July

2014

for

$73

MM

gross

•

Eagle

Ford

oil

gathering/transportation

rights

–

closed

July

2014

for

$150

MM

gross

•

Eagle

Ford

gas

gathering/gas

lift

assets

–

closed

January

2014

for

$94

MM

gross

•

Arbitration award of $35 MM

5

(1) Pro forma to exclude divested Mississippi volumes.  Assumes 64 (36.5 net) TILs (turn-in lines) for the balance of 2014, of which 14 (12.3 net) wells will be in the Upper Eagle Ford, 22 (9.0 net) wells will be in the “Beer

Quad”,

8

(4.3

net)

wells

will

be

in

Peach

Creek

and

11

(4.3

net)

will

be

in

Rock

Creek

Ranch,

with

6

(3.9

net)

shallow

wells

and

three

(2.8

net)

wells

in

other

areas

of

Shiner.

Shallow

wells

are

wells

with

less

than

10,500’

of

vertical depth (defined as measured depth less lateral length)

•

We have significantly

increased oil production

over the last few years,

and we expect that trend

to continue

•

Addition of 7

th

and 8

th

rigs is anticipated to

provide total production

growth

of

35

-

45%

and

oil

production growth of 45 -

60% in 2015

•

Anticipate 64 (36.5 net)

TILs during 2H14

2014-2015

Historical

and

Estimated

Production

Growth

(1)

PVA is an Eagle Ford Oil Growth Story

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

1Q14

2Q14

3Q14-E

4Q14-E

2015-E

Pro Forma Daily Production by Quarter and 2015

Oil (BOPD)

NGL (BOPD)

Gas (BOEPD)

Pro Forma

Guidance

Range

Guidance

Range

Pro Forma

Production

Pro Forma

Production

Guidance

Range

PVA

BHP Billiton

ConocoPhillips

Devon

EOG

Forest / Sabine

Nearby Operators

Marathon

Earthstone

Pioneer

Plains

Sabine / Forest

Sanchez

Gonzales

Lavaca

DeWitt

6

Overview of PVA’s Eagle Ford Position

•

142,500 gross (101,800 net) acres

(1)

•

Avg. IP/30-day rates of 1,490/943 BOEPD for the last 82/68 wells in the

Peach

Creek,

Rock

Creek,

Bozka

and

Shiner

Areas

(2)

•

16,860 net BOEPD of June 2014 Eagle Ford sales (74% oil; 15% NGLs)

•

Proved

PV-10

at

YE13

of

$1,584

MM

($754

MM

of

PD

value)

(3)

Approximately 190 MMBOE of 3P reserves at YE13, excluding Upper

Eagle Ford upside

(4)

•

Greater than 1,600 remaining gross drilling locations

•

Positive down-spacing results associated with pad drilling

•

Additional upside potential in Upper Eagle Ford (Marl) and Austin Chalk

•

Rigs and infrastructure in place

•

Drilling

plan

includes

8

rigs

in

2H14;

64

(36.5)

net

wells

to

be

TIL in 2H14

•

Multiple providers of frac stimulation services

•

Monetized gas gathering and gas lift systems and oil gathering and

transportation rights in 1H14 for approximately $245 MM

(1) 

Acreage and location data includes impact of Eagle Ford acquisition announced on 7/10/14 and expected to close in August 2014. 

(2)

Since the beginning of 2Q13; excludes  “shallow” wells. Shallow wells are wells with less than 10,500’ of vertical depth (defined as measured depth less lateral length).

(3)

Based on SEC proved reserve estimates as of 12/31/13.  See reconciliation to standardized measure in appendix.

(4)

3P reserves based on internal estimates of probable and possible reserves as of 12/31/13.

Emerging Presence in Leading U.S. Oil Shale Play

7

Growing Our Eagle Ford Position

Increases in Production, Revenues and Reserves

Growth in Eagle Ford Production

Growth in Eagle Ford Proved Reserves

Growth in Eagle Ford Revenues

Growth in Eagle Ford 3P Reserves

PVA's Concentrated Position in the Eagle Ford

Over

100,000

Net

Acres

in

the

Core

of

the

Eagle

Ford

(1)

8

(1) Acreage and location data includes impact of Eagle Ford acquisition announced on 7/10/14 and expected to close in August 2014.

9

Currently have >600

Upper Eagle Ford

(Marl) Shale Drilling

Locations

•

Located in the eastern portion of our Lavaca County acreage position

•

Potential of the Upper Eagle Ford has expanded to the east and west with the

recent results of our Welhausen and Martinsen wells

Additional 400

Drilling Locations

May Exist On

"Legacy" Acreage

•

Located in the Peach Creek Field and other portions of the Shiner Field

•

For

now,

our

inventory

assumes

only

“lower”

Eagle

Ford

locations

in

these

areas

Early Upper Eagle

Ford Results Have

Been Very

Encouraging

•

PVA’s two recent test wells: Welhausen #A2H and Martinsen #2H

•

Welhausen #2H IP –

2,165 BOEPD (26 frac stages); 1,070 BOEPD over 95 days

•

Martinsen #2H IP –

1,360 BOEPD (27 frac stages); 1,238 BOEPD over 30 days

•

Plan to spud 19 and TIL 14 (12.3 net) Upper Eagle Ford wells in 2H14

210 to 450 MMBOE

of Gross Resource

Potential May Exist

Across Our Current

Acreage

•

Assumes an EUR range of 350 to 450 MBOE per well

•

Assumes 600 to 1,000 gross drilling locations

Upper Eagle Ford / Marl Upside

Lavaca

Gonzales

Fayette

Lavaca

Gonzales

Lavaca

FEET

0

13,954

Upper Eagle Ford / Marl Upside

10

Devon Medina #2H

Drilling

Sabine –

Sustr #1H

IP 1,054 BOEPD IP30 869 BOEPD

Sabine –

Targac #1H

IP 1,226 BOEPD IP30 840 BOEPD

Sabine –

Gillespie #1H

IP 843 BOEPD IP30 654 BOEPD

Tier 1 Fairway

Existing Completions

2014 Spuds (1-2 well pads)

PVA Leasehold

Upper Eagle Ford / Marl

Penn Virginia Martinsen #2H

IP 1,360 BOEPD IP30 1,238 BOEPD

CUM 56,187 1.7 months

27 frac stages / 5,857’

lateral

Penn Virginia Fojtik #1H

IP 1,209 BOEPD IP30 684 BOEPD

CUM 97,308 BOE –

15.4 months

17 frac stages / 4,202’

lateral

Penn Virginia Welhausen #A2H

IP 2,165 BOEPD IP30 1,767 BOEPD

CUM 101,685 –

3.1 months

26 frac stages / 5,976’

lateral

Upper EF Performance Substantiates Development

Plan to spud 19 and TIL 14 (12.3 net) Upper Eagle Ford wells in 2H14

2014 Upper Eagle Ford Tests

Welhausen #A2H

•

26 frac stages

•

IP: 2,165 BOEPD

83.3 BOEPD / stage

•

IP95: 1,070 BOEPD

41.1 BOEPD / stage

Martinsen #2H

•

27 frac stages

•

IP: 1,360 BOEPD

50.4 BOEPD / stage

•

IP30: 1,238 BOEPD

45.9 BOEPD / stage

11

0

10

20

30

40

50

60

70

80

90

100

15

30

45

60

75

90

Days on Production

Upper Eagle Ford Shale

Aligned Days of Production

Internal Shiner Type Curve

Welhausen #A2H

Martinsen #2H

•

Due to acquisitions and leasing efforts, our acreage position currently stands at 142,500 gross

(101,800 net) acres

(1)

•

We have an inventory of 1,600+ gross potential identified drilling locations, generating a      

~12-year inventory with 8 rigs

•

3 successful tests of Upper Eagle Ford (Marl) thus far, 19 more spuds planned for 2H14

•

Inventory will continue to increase with an ongoing active leasing program

•

Potential for additional 400 stacked lateral Upper Eagle Ford locations overlying Lower Eagle Ford locations

12

Note: Latest through 07/31/14

(1)

Acreage and location data Includes impact of Eagle Ford acquisition announced on 7/10/14 and expected to close in August 2014.

(2)

Includes over 600 undeveloped and 3 developed Upper Eagle Ford (Marl) Shale locations and wells in Shiner.

(3)

Represents gross acres per location. Actual location count depends upon lease configurations, lateral lengths and spacing between laterals.

Area

Producing

Wells

Drilling

Locations

(2)

Gross

Acreage

Net

Acreage

Acres /

Location

(3)

Shiner-

Upper

EF

(1,2)

3

617

30,025

26,571

48

Shiner

-

Beer

Quad

22

48

6,400

3,354

91

Shiner

-

Other

28

417

37,957

31,603

85

Peach Creek

125

311

32,007

16,696

73

Rock Creek / Bozka

22

78

6,472

5,084

65

Shallow / Hunt

31

179

29,647

18,472

141

Totals

231

1,650

142,508

101,780

76

Eagle Ford Drilling Inventory

Inventory of Drilling Locations Increasing Due to Leasing and Downspacing

2H 2014 Work Program Focused on Best Areas

13

Notes

Includes Eagle Ford wells over the past five quarters.  The 58 gross wells panned for 2H14 excludes six shallow wells.

22

14

11

8

0

3

58 Gross TILs

2H 2014:

0

10

20

30

40

50

60

70

80

0

250

500

750

1,000

1,250

1,500

1,750

2,000

Shiner High

GOR

Rock Creek

Bozka

Peach Creek

Shiner -

Mod

GOR

Upper EF

Shiner Beer

Quad

Initial Production (Boe/d; left axis)

Initial Production (per stage; right axis)

Initial Production per Area

Well Costs per Stage are Declining

14

Notes

-

Excludes shallow wells.

$0

$100

$200

$300

$400

$500

$600

$700

$800

2011

2012

2013

1H14

Annual Trend in Average Well Costs per Frac Stage

•

Normalizing production for number of frac stages, the last 55 wells in Peach Creek have

a tight fit with both the YE13 external and internal type curve per frac stage over the

past 24 months

•

Normalizing production for number of frac stages, the last 65 wells in Shiner have a

tight fit with the internal type curve per frac stage over the past 18 months

Gross Production Actuals vs. Type-Curves

Average Production per Frac Stage of Recent Wells vs. YE13 External and Internal Type Curves

15

(1) Based on YE13 type curve per outside reservoir engineering firm. Terminal declines of 12% in both Peach Creek and Shiner begin at 7.8 years and are higher than internal terminal decline estimates.

(2) Gross EUR assumes 13.1 MBOE of EUR per frac stage in Peach Creek (11.3 thousand barrels of oil (MBO), 1.0 MBO of NGLs and 133 Mcf of gas) and 17.9 BOE per frac stage in Shiner (11.5 MBO, 3.4 MBO of NGLs and 489 Mcf of gas).

(3) Internal

reserves

are

based

on

recent

results

in

those

areas

in

which

the

majority

of

our

future

drilling

program

will

occur.

(4) Assumes a flat $80 or $100 per barrel WTI oil price.

(5) Capital cost plus before tax PV-10 divided by capital cost.

Eagle Ford Well Economics

Pretax IRR Sensitivities –

Excellent Returns in Primary Development Areas

Peach Creek Field

•

Assumes 28 frac stages

•

367 MBOE EUR type curve

(1)

; 86% oil, 8% NGLs

(2)

•

Drilling and completion costs of $8.4 MM ($301K/stage)

•

Internal estimates, which include a 5% terminal decline

assumption, yield a 520 MBOE type curve

(3)

Shiner Field

•

Assumes 27 frac stages

•

484 MBOE EUR type curve

(1)

; 65% oil, 19% NGLs

(2)

•

Drilling and completion costs of $9.2 MM ($342K/stage)

•

Internal estimates, which include a 5% terminal decline

assumption, yield a 680 MBOE type curve

(3)

Key Takeaways

$80 WTI Price

$100 WTI Price

IRR

(4)

40%

72%

BTAX PV-10

(4)

($MM)

$4.7

$8.0

PV/I

(5)

1.51

1.87

Key Takeaways

$80 WTI Price

$100 WTI Price

IRR

(4)

45%

83%

BTAX PV-10

(4)

($MM)

$4.7

$7.9

PV/I

(5)

1.55

1.94

16

17

Maintain at Least         

$150 MM of

Financial Liquidity

•

Pro forma 2Q 2014 liquidity of $625 MM

•

Reflects net proceeds from recent asset sales and arbitration settlement, net of

pending Eagle Ford acquisition

Target Debt-to-

Adjusted EBITDAX   

< 2.5x

•

Pro forma 2Q 2014 net leverage ratio of 2.5x

•

Potential to achieve target in the next 18 months

•

Any additional non-core asset sales would accelerate this goal

Protect Cash Flows

with Hedges

•

~82% of 2H14 and ~57% of 2015 oil production hedged; commenced 2016 hedging

•

Target 70% of production while leverage is higher than 3.0x

•

Protect minimum $85 WTI oil price along with some upside

Continue to Invest in

High Return

Development

Projects

•

90%+ of capital investment is in Eagle Ford development

•

Wellhead

rates

of

return

of

50%

–

60%

at

$90

WTI

price

(70%

–

80%

at

$100

WTI)

•

Operational flexibility to continue to high-grade drilling program

Financial Strategy

Focus on a Strong Balance Sheet and Value Creation

Capitalization and Credit Stats

18

Improving Credit Statistics and Liquidity

(1)  Market value for 6% Series A and Series B Convertible Preferred Stock depositary shares calculated based on closing prices of each issue at 6/30/14 and 8/20/14.

(2)  Market value for common share  based on closing price at 6/30/14 and 8/20/14.

Capitalization ($ millions)

6/30/14

Market

Adjustments

Asset Sales/

Acquisition

Adjustments

Pro Forma

6/30/14

Cash

$25

$162

$187

Debt

Credit Facility

$55

($55)

-

Senior Notes

1,075

1,075

Total Debt

$1,130

$0

($55)

$1,075

6% Convertible Series A Preferred (PVAYL: $88.8MM face value)

(1)

300

(89)

211

6% Convertible Series B Preferred (PVGPP: $325MM face value)

(1)

358

(33)

325

Market Cap

(2)

1,185

(219)

966

Enterprise Value

$2,973

($340)

($55)

$2,578

Proved Reserves (MMBOE)

136

(14)

122

Year-End 2013 PV-10

$1,717

($45)

$1,672

Credit Statistics

6/30/14

PF 6/30/14

Net Debt /

Proved Reserves ($/BOE)

$8.11

$7.27

LTM Adjusted EBITDAX

3.1x

2.5x

PV-10 / Net Debt

1.6x

1.9x

Net Debt / EV

37%

34%

Liquidity

$445

$625

Company Highlights

19

Premier Eagle Ford

Position

•

~101,800

net

acres

in

the

Eagle

Ford

with

~12

years

of

drilling

inventory

(1)

•

Continued acreage growth through organic leasing and bolt-on acquisitions

Operational

Excellence

•

Beginning to delineate Upper Eagle Ford, generating over 600 gross locations

•

Significant Upper Eagle Ford reserve and production upside

•

Pad drilling and “zipper fracs”

enhancing drilling returns

•

Focused

development

program

has

generated

substantial

production

growth

in

the

Eagle

Ford,

increasing

from

2.3

MBOEPD

in

2011

to

16.9

MBOEPD

in

2Q

2014

•

Initial production rates remain strong with attractive drilling economics

Sufficient Liquidity

to Execute Future

Drilling Schedule

•

Recent offering, cash flow from operations and availability under our revolver

provide liquidity to fund our anticipated development program

•

Asset sales increased liquidity and decreased leverage

(1) Acreage and location data includes impact of Eagle Ford acquisition announced on 7/10/14 and expected to close in August 2014.

20

Appendix

Note:

Some EFS operators off map.

(1)

Based on recent company presentations, as well as industry publications.  Some industry publication information may be out of date.

Eastern

Volatile

Oil

and

Condensate

Rich

Gas

Windows

(1)

21

Overview of the Eagle Ford

PVA

BHP

CHK

COG

COP

CRK

CRZO

DVN

EOG

FST/Sabine

MRO

MUR

NFX

Earthstone

PXD

PXP

Sabine/FST

SFY

SN

STO

TLM

EFS Operators

Casing

Oil

Oil

Gas

Equiv

%

Pressure

Gravity

Location

(BOPD)

(MCFD)

(BOEPD)

Rank

Oil

GOR

(psi)

API-60°

Shiner - "Beer Quad" (Mod. GOR)

1,581

1,904

1,899

72.4

                   1

83%

1,285

2,952

47.1

Shiner - Upper Eagle Ford (Marl)

917

5,077

1,763

66.8

                   2

52%

5,444

3,788

53.5

Shiner - Moderate GOR

1,118

1,372

1,346

62.6

                   3

83%

1,225

2,931

47.9

Rock Creek Ranch / Bozka

1,339

1,131

1,527

60.6

                   4

88%

841

2,341

45.1

Peach Creek

1,295

790

1,426

57.9

                   5

91%

592

1,981

44.2

Shiner - High GOR

833

2,136

1,189

55.5

                   6

70%

2,645

3,396

49.5

Totals and Averages

1,244

1,474

1,490

61.7

84%

1,321

2,652

46.6

Oil

Gas

Equiv

30-Day/IP

%

Location

(BOPD)

(MCFD)

(BOEPD)

Rank

BOEPDPS

Oil

GOR

Shiner - "Beer Quad" (Mod. GOR)

1,097

1,458

1,340

50.8

                   2

68%

82%

1,329

Shiner - Upper Eagle Ford (Marl)

830

4,038

1,502

56.9

                   1

86%

55%

4,809

Shiner - Moderate GOR

628

809

763

35.5

                   5

59%

82%

1,296

Rock Creek Ranch / Bozka

848

645

955

39.0

                   3

73%

89%

787

Peach Creek

868

540

958

38.3

                   4

63%

91%

598

Shiner - High GOR

500

1,261

706

33.1

                   6

60%

70%

2,571

Totals and Averages

779

984

943

39.2

64%

83%

1,378

Initial Potential

30-Day Average

BOEPD/

Stage

(BOEPDPS)

BOEPD/

Stage

(BOEPDPS)

BOEPDPS

BOEPDPS

Detailed Analysis of EFS Wells by Location

22

Wells TIL Since 4/1/13 -

Excludes Non-Operated and “Shallow”

Wells

Notes

-

“Beer Quad”

wells are moderate GOR wells, with beer types in their names, located primarily in Lavaca County to the northwest of the town of Shiner.

-

“Shiner -

Moderate GOR”

wells are located to the east and northeast of the “Beer Quad.”

-

Excluded

shallow

wells

are

wells

with

less

than

10,500’

of

vertical

depth

(defined

as

measured

depth

less

lateral

length).

-

Sorted by ranking of IP BOEPD / frac stage.

-

In the “Shiner -

Upper Eagle Ford (Marl)”

location, the 30-day information pertains to one well. The other two wells have not yet had 30 days of production information.

Detailed Analysis of EFS Wells by Location

23

Notes

-

“Beer Quad”

wells are moderate GOR wells, with beer types in their names, located primarily in Lavaca County to the northwest of the town of Shiner.

-

“Shiner -

Moderate GOR”

wells are located to the east and northeast of the “Beer Quad.”

-

Excluded

shallow

wells

are

wells

with

less

than

10,500’

of

vertical

depth

(defined

as

measured

depth

less

lateral

length).

-

Sorted by ranking of IP BOEPD / frac stage.

-

In the “Shiner -

Upper Eagle Ford (Marl)”

location, the 30-day information pertains to one well. The other two wells have not yet had 30 days of production information.

Wells TIL Since 4/1/13 -

Excludes Non-Operated and “Shallow”

Wells

Gross

Net

WI

Location

Wells

Wells

(%)

Shiner -

"Beer Quad" (Mod. GOR)

17

8.0

47%

Shiner -

Upper Eagle Ford (Marl)

2

1.9

94%

Shiner -

Moderate GOR

12

9.2

77%

Rock Creek Ranch / Bozka

8

3.7

47%

Peach Creek

29

13.6

47%

Shiner -

High GOR

14

12.5

89%

Totals and Averages

82

48.8

60%

No. of

Lateral

Lat. Length

Vertical

Frac

Proppant

Length

per Stage

+ Curve

Location

Stages

(lbs)

(ft)

(ft/stage)

(lbs)

Rank

(lbs)

Rank

(ft)

Shiner -

"Beer Quad" (Mod. GOR)

26.4

9,350,587

5,970

226

354,222

2

1,582

2

12,483

Shiner -

Upper Eagle Ford (Marl)

26.5

9,970,830

5,917

223

376,349

1

1,686

1

13,125

Shiner -

Moderate GOR

21.7

6,579,536

5,124

236

302,518

4

1,295

5

12,342

Rock Creek Ranch / Bozka

26.8

9,041,509

6,152

237

333,514

3

1,441

3

11,047

Peach Creek

25.8

7,800,856

5,982

232

301,591

5

1,324

4

11,264

Shiner -

High GOR

21.6

6,144,944

4,928

229

282,999

6

1,253

6

12,841

Totals and Averages

24.7

7,834,661

5,689

231

314,401

1,381

11,968

Proppant

per Stage

Proppant

per Stage

Drilling and Completion Information

Proppant

per Foot

Proppant

per Foot

24

Internal Well Economics

(1) Based on latest internal type curve. Terminal decline of 5%n

both Peach Creek and Shiner, as opposed to 12% terminal decline

per outside reservoir engineering report.

(2) Gross EUR assumes 18.5 MBOE of EUR per frac stage in Peach Creek (15.9 MBO of oil, 1.4 MBO of NGLs and 188 Mcf of gas) and 25.2 BOE per frac stage in Shiner (16.2 MBO, 4.8 MBO of NGLs and 687 Mcf of gas).

(3) The majority of our future drilling program will occur in these areas. Type curve utilized is supported with early time production information.

(4) Assumes a flat $80 or $100 per barrel WTI oil price.

(5) Capital cost plus before tax PV-10 divided by capital cost.

Note: Internal type curves represent management's best estimates

of type curves and may differ from those of our third-party reserve engineers. Financial reporting reserves are based on the type curves of our third-party reserve engineers. Both the

internal type curves and those of our third-party reserve engineers are estimates based on limited data. There can be no assurance that actual production will conform with either set of type curves.

Pretax IRR Sensitivities –

Superior Returns in Peach Creek and Shiner

Peach Creek Field

•

Assumes 28 frac stages

•

520 MBOE EUR type curve

(1)

; 86% oil, 8% NGLs

(2)

•

Drilling and completion costs of $8.4 MM ($301K/stage)

•

Internal reserves based on recent well results using a higher

IP, lower initial decline rate and 5% terminal decline rate

(3)

Shiner Field

•

Assumes 27 frac stages

•

680 MBOE EUR type curve

(1)

; 65% oil, 19% NGLs

(2)

•

Drilling and completion costs of $9.2 MM ($342K/stage)

•

Internal reserves based on recent well results using a higher

IP, lower initial decline rate and 5% terminal decline rate

(3)

Key Takeaways

$80 WTI Price

$100 WTI Price

IRR

(4)

61%

118%

BTAX PV-10

(4)

($MM)

$7.7

$11.7

PV/I

(5)

1.83

2.27

Key Takeaways

$80 WTI Price

$100 WTI Price

IRR

(4)

69%

136%

BTAX PV-10

(4)

($MM)

$7.5

$11.4

PV/I

(5)

1.88

2.35

Crude Oil Hedges (Swaps and Collars)

(1)

Natural Gas Hedges (Swaps and Collars)

(1)

•

Maintain an active hedging program to help support capital spending program and

ensure strong coverage metrics

•

Hedges in place to protect cash flow

•

Latest oil hedges:

–

12,500 BOPD (82% of est. vol.) is hedged for 2H14 at an average floor price of $92.80

–

11,500

BOPD

(~57%

of

est.

vol.)

is

hedged

for

2015

at

an

average

floor

price

of

$90.17

–

3,000 BOPD is hedged for 2016 at an average floor price of $90.84

•

Latest natural gas hedges:

–

10,000 MMBtu/d (~30% of est. vol.) is hedged for 2H14 at an average floor price of $4.20

–

5,000 MMBtu/d is hedged for 1Q15 at an average floor price of $4.50

25

(1)

As of 8/21/14.

Protect Cash Flow

Hedging Strategy

1Q14

2Q14

1H14

Low

High

Low

High

Production:

Crude oil (MBbls)

1,076

1,119

2,195

2,685

-

2,915

4,880

-

5,110

NGLs (MBbls)

227

261

488

625

-

685

1,113

-

1,173

Natural gas (MMcf)

3,593

3,618

7,211

5,946

-

6,552

13,157

-

13,763

Equivalent production (MBOE)

1,902

1,983

3,885

4,301

-

4,692

8,186

-

8,577

Equivalent daily production (BOEPD)

21,133

21,786

21,461

23,375

-

25,500

22,426

-

23,497

Percent crude oil and NGLs

68.5%

69.6%

69.1%

73.6%

-

80.1%

71.5%

-

75.0%

Production revenues (a):

Crude oil

$105.6

$112.1

$217.7

$235.3

-

$262.3

$453.0

-

$480.0

NGLs

9.4

8.0

17.4

20.6

-

25.6

38.0

-

43.0

Natural gas

18.2

16.3

34.5

25.5

-

31.5

60.0

-

66.0

Total product revenues

$133.2

$136.4

$269.6

$281.4

-

$319.4

$551.0

-

$589.0

Total product revenues ($ per BOE)

$70.01

$68.81

$69.40

$65.43

-

$68.08

$67.31

-

$68.68

Percent crude oil and NGLs

86.3%

88.1%

87.2%

85.2%

-

95.8%

86.1%

-

91.8%

Adjusted EBITDAX (b)

$93.8

$95.0

$188.8

$210.0

-

$245.0

$398.8

-

$433.8

Capital expenditures:

Drilling and completion

$135.5

$154.0

$289.5

$320.4

-

$339.4

$609.9

-

$628.9

Lease acquisitions

36.9

12.8

49.7

47.3

-

65.3

97.0

-

115.0

Seismic (c)

4.5

0.1

4.6

3.4

-

4.4

8.0

-

9.0

Pipeline, gathering, facilities and other

5.6

2.6

8.2

8.8

-

10.8

17.0

-

19.0

  Total oil and gas capital expenditures

$182.4

$169.5

$351.9

$380.0

-

$420.0

$731.9

-

$771.9

End of period debt outstanding

$1,265.0

$1,130.0

$1,130.0

$1,075.0

-

$1,075.0

$1,075.0

-

$1,075.0

2014 Guidance

2H14

26

Full-Year and Second-Half 2014 Guidance

(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

$35.00

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.

Current Derivative Positions as of 8/21/14

Notes:

(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

intoa

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

thesecond

half

of

2014

wouldincrease

or

decrease

by

approximately

$7.9

million.

This

assumes

that

crude

oil

prices,

natural

gas

pricesand

inlet

volumes

remain

constantat

anticipated

levels.

These

estimated

changes

in

operating

income

exclude

potential

cash

receipts

or

payments

in

settling

these

derivative

positions.

27

Derivatives

Weighted Average Price

Instrument Type

Average Volume Per Day

Floor/ Swap

Ceiling

Natural gas:

(MMBtu)                                      ($ / 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)                         ($ / 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

2009

2010

2011

2012

2013

Adjusted EBITDAX

Net income (loss) from continuing operations

$    (130.9)

$    (65.3)

$  (132.9)

$  (104.6)

$  (143.1)

$    (182.8)

Add: Income tax expense (benefit)

         (85.9)

(42.9)

(88.2)

(68.7)

(77.7)

(97.7)

Add: Interest expense

          44.2

53.7

56.2

59.3

78.8

88.3

Add: Depreciation, depletion and amortization

154.4

134.7

162.5

206.3

245.6

273.3

Add: Exploration

57.8

49.6

78.9

34.1

21.0

18.9

Add: Share-based compensation expense

9.1

7.8

7.4

6.3

5.8

3.7

Add/Less: Derivatives (income) expense included in net income

(31.6)

(41.9)

(15.7)

(36.2)

20.9

80.0

Add/Less: Cash receipts (payments) to settle derivatives

          58.1

         32.8

         27.4

         29.7

         (1.0)

(17.1)

Add/Less: Loss on firm transportation commitment

               - 

              - 

              - 

         17.3

              - 

-

Add: Impairments

106.4

46.0

104.7

104.5

132.2

250.1

Add/Less: Net loss (gain) on sale of assets, other

           (2.0)

         (1.2)

         22.0

         (0.6)

         33.7

         (55.2)

Adjusted EBITDAX

$     179.7

$    173.3

$    222.5

$    247.6

$    316.2

$      361.5

Pro Forma Adjusted EBITDAX

$    342.4

$      361.5

dollars in millions

Year ended December 31,

LTM

2Q14

Non-GAAP Reconciliation

28

Adjusted EBITDAX Reconciliation