Total and Daily Equivalent Production for the Three Months Ended
Region / Play Type
?
?
Mar. 31,
2012
?
?
Mar. 31,
2011
?
?
Dec. 31,
2011
?
?
Mar. 31,
2012
?
?
Mar. 31,
2011
?
?
Dec. 31,
2011
(in Bcfe)
(in MMcfe per day)
Texas
5.3
?
?
3.8
?
?
4.9
58.7
?
?
42.5
?
?
53.2
Cotton Valley/Other
1.4
2.2
1.6
15.5
24.8
17.6
Haynesville Shale
0.8
1.4
0.9
8.7
16.0
9.6
Eagle Ford Shale(1)
3.1
0.1
2.4
34.6
1.6
26.0
Appalachia
2.1
2.4
2.2
22.7
26.3
23.6
Mid-Continent(2)
2.1
4.1
2.2
23.6
45.8
24.3
Granite Wash
2.0
3.1
2.2
22.0
33.9
24.4
Mississippi
1.3
?
?
1.9
?
?
1.4
14.5
?
?
20.7
?
?
15.6
Totals
10.9
?
?
12.2
?
?
10.7
119.5
?
?
135.2
?
?
116.7
Pro Forma Totals(3)
10.9
?
?
11.5
?
?
10.7
119.5
?
?
127.9
?
?
116.7
?
(1)
?
Initial production from the Eagle Ford Shale commenced in February 2011.
(2)
Includes production from the Mid-Continent assets sold in 2011.
(3)
Pro forma to exclude production from the Mid-Continent assets sold in 2011.
Note - Numbers may not add due to rounding.
Operating Expenses
First quarter 2012 total direct operating expenses decreased $3.5 million, or approximately 11 ?percent, to $27.4 ?million, or $2.52 ?per Mcfe produced, compared to $30.9 million, or $2.54 per Mcfe produced, in the prior year quarter.
Lease operating expenses decreased by $1.1 million, or 11 percent, to $9.2 million, or $0.84 ?per Mcfe produced, from $10.3 million, or $0.84 per Mcfe produced, in the prior year quarter due to lower production volumes as well as the sale of higher-cost Arkoma Basin properties in August 2011. Despite the decrease in costs, the unit cost was flat due to lower production volumes.
Gathering, processing and transportation expenses increased by approximately $0.2 million, or three percent, to $4.2 ?million, or $0.38 per Mcfe produced, from $4.0 million, or $0.33 per Mcfe produced, in the prior year quarter, despite lower overall production volumes, due primarily to firm transportation costs in the Appalachian region and a prior-period adjustment related to gathering volumes in the Mid-Continent.
Production and ad valorem taxes decreased 29 percent to $3.6 ?million, or 4.3 percent of product revenues, from $5.1 ?million, or 7.5 percent of product revenues, in the prior year quarter resulting from lower natural gas prices and lower severance tax rates for certain wells in Texas and Oklahoma.
General and administrative (G&A) expenses, excluding share-based compensation, decreased by $1.0 ?million, or nine ?percent, to $10.5 ?million, or $0.97 per Mcfe produced, from $11.5 million, or $0.95 per Mcfe produced, in the prior year quarter. This decrease was due primarily to lower employee headcount and lower support costs following restructuring actions taken during 2011.
Exploration expense decreased $21.5 million, or 73 percent, to $8.0 ?million in the first quarter of 2012 from $29.5 ?million in the prior year quarter. The decrease was due primarily to a $16.4 million decrease in dry-hole costs (zero in the first quarter of 2012), a $2.4 ?million decrease in unproved property amortization and a $2.2 million decrease in geological and geophysical costs.
DD&A expense increased by $16.0 million, or 46 percent, to $50.8 ?million, or $4.67 per Mcfe produced, in the first quarter of 2012 from $34.8 million, or $2.86 per Mcfe produced, in the prior year quarter, due primarily to higher DD&A costs attributable to our Eagle Ford Shale oil wells, which is typical for this and other oily plays, as well as downward revisions in proved reserves located primarily in the Granite Wash, East Texas and Mississippi at year-end 2011.
Capital Expenditures
During the first quarter of 2012, capital expenditures were approximately $90 million, compared to $104 ?million in the prior year quarter and $123 million in the fourth quarter of 2011, consisting of:
$83 million for drilling and completion activities, including 11 (9.4 net) wells, all of which were successful
$3 million for seismic, pipeline, gathering and facilities
$4 million for leasehold acquisitions and other
Operational Update
Eagle Ford Shale
During the first quarter of 2012, we drilled 11 (9.4 net) operated wells in the Eagle Ford Shale, all of which were successful. We currently have two rigs drilling our 46th and 47th wells, one well that is WOC and 44 (36.6 net) wells that are producing. As shown in the table below, the average peak gross production rate per well for 40 of these wells which had full-length laterals was approximately 1,000 ?BOEPD. The initial 30-day average gross production rate for 35 of these 40 wells with sufficient production history was approximately 650 ?BOEPD. Eagle Ford Shale production was approximately 9,200 (5,800 net) BOEPD during the first quarter of 2012, with oil comprising approximately 88 ?percent, NGLs approximately six percent and natural gas approximately six percent.
In late 2011, we announced a 13,500 acre AMI with a major oil and gas company in Lavaca County, Texas pursuant to which, during 2012, we can earn a minimum of approximately 8,000 net acres. This would bring our Eagle Ford Shale position in Gonzales and Lavaca Counties, Texas to a minimum of approximately 31,400 (23,100 net) acres, with up to 190 total well locations assuming down-spacing is successful on a majority of our acreage.
The first two wells on the Lavaca County acreage (Effenberger #1H and Vana #1H) were completed and turned in line during April 2012. Both wells have met or exceeded our expectations with the Effenberger #1H (20 frac stages and lateral length of approximately 5,000 feet) averaging 922 BOEPD of wellhead volumes over its first nine days of production (90 percent oil and 10 percent wet gas) and the Vana #1H (13 frac stages and lateral length of approximately 3,200 feet) averaging 709 ?BOEPD of wellhead volumes over its first five days of production (94 percent oil and six percent wet gas). The lateral length of the Vana #1H well was less than expected by approximately 1,600 feet due to an issue with getting casing to the total depth drilled. Taking into account the lateral lengths, both wells appear to have similar production characteristics during the initial flowback of frac fluids and are comparable to well results experienced in nearby Gonzales County. Both wells are significantly choked with the flowing pressure on the Effenberger #1H well at the end of the nine days of approximately 3,450 pounds per square inch (psi) and the flowing pressure on the Vana #1H well at the end of the five days of approximately 2,300 psi, as the recovery of fluid continues. A third well in Lavaca County (Schacherl #1H) is currently being drilled, with three additional wells expected to be drilled during 2012.
Our full-year 2012 guidance anticipates 32 ?(27.6 ?net) new wells in the Eagle Ford Shale, including the wells drilled during the first quarter of 2012. Efforts continue to expand our Eagle Ford Shale position through additional leasing and selective acquisitions.
?
?
?
?
?
?
?
?
?
?
Cumulative Gross
Production(4)
Peak Gross Daily
Production Rates(4)
30-Day Average Gross
Daily Production Rates(4)
Well Name
?
?
Lateral
Length
?
?
Frac
Stages
Equivalent
Production
?
?
Days On
Line
Oil
Rate
?
?
Equivalent
Rate
Oil
Rate
?
?
Equivalent
Rate
Feet
BOE
?
?
BOPD
?
?
BOEPD
BOPD
?
?
BOEPD
Previously Reported On-Line Wells
Gardner #1H
4,792
16
159,852
451
1,084
1,247
732
881
Hawn Holt #1H
4,352
15
103,270
357
759
837
606
668
Hawn Holt #4H
4,106
14
67,850
354
534
582
357
394
Hawn Holt #6H
4,166
17
69,971
325
670
711
342
370
Hawn Holt #2H
4,476
17
104,452
324
869
986
668
728
Hawn Holt #9H
4,453
18
132,210
373
1,652
1,877
1,044
1,153
Hawn Holt #10H
3,913
16
97,568
296
1,080
1,188
771
839
Hawn Holt #5H
3,950
16
54,657
288
474
528
321
349
Hawn Holt #3H
3,800
15
64,309
288
607
651
478
522
Munson Ranch #1H
4,163
17
150,240
279
1,755
1,921
1,207
1,315
Munson Ranch #3H
3,953
16
113,041
278
1,448
1,538
1,007
1,092
Hawn Holt #11H
3,931
16
82,235
274
1,120
1,190
786
860
Dickson Allen #1H
3,953
15
46,973
243
465
508
358
393
Hawn Holt #7H
4,345
18
60,259
244
730
798
493
541
Hawn Holt #12H
3,320
18
75,296
235
1,458
1,495
619
668
Hawn Holt #13H
2,805
11
62,938
222
1,347
1,399
591
650
Cannonade Ranch #1H
4,403
18
48,889
227
377
403
255
274
Hawn Holt #15H
4,153
17
100,782
203
1,191
1,298
779
838
Hawn Holt #8H
4,203
17
49,170
195
427
492
361
409
Dickson Allen #2H
3,853
16
65,387
196
552
601
460
516
Gardner #2H
2,953
12
31,729
170
551
579
312
346
Munson Ranch #2H
3,953
16
57,838
166
819
869
515
572
Rock Creek Ranch #1H
3,444
14
68,261
140
1,158
1,257
639
708
Munson Ranch #8H
3,403
14
43,347
133
914
964
561
606
Munson Ranch #4H
3,864
16
62,588
132
1,317
1,416
807
870
Munson Ranch #6H
3,415
14
61,917
123
1,717
1,808
845
928
Schaefer #2H
3,707
12
23,450
110
586
638
305
334
Schaefer #3H
2,903
12
42,253
108
1,035
1,129
546
604
Schaefer #1H
2,992
13
40,349
109
871
941
536
584
Munson Ranch #5H
3,153
13
51,446
88
1,063
1,164
723
791
Munson Ranch #7H
3,153
13
36,295
88
757
824
506
548
Hawn Dickson #1H
3,153
13
30,520
84
923
969
472
509
?
New On-Line Wells
D. Foreman #1H
3,398
14
35,044
66
1,133
1,202
637
678
Rock Creek Ranch #2H
3,455
14
26,543
55
700
791
---
---
Culpepper #2H
4,903
20
18,649
49
531
560
388
413
Henning #1H
3,703
15
21,412
37
1,056
1,115
565
614
Rock Creek Ranch #6H
3,150
13
16,471
20
857
960
---
---
Rock Creek Ranch #5H
3,203
13
15,542
20
870
969
---
---
Effenberger #1H(5)
4,950
20
7,517
9
845
922
---
---
Vana #1H(5)
3,192
13
2,817
5
655
709
---
---
?
Averages
3,778
15
60,083
184
924
1,001
588
645
Maximums
4,950
20
159,852
451
1,755
1,921
1,207
1,315
Minimums
2,805
11
2,817
5
377
403
255
274
?
Other Wells
Cannonade Ranch #3H(6)
3,451
12
7,192
91
205
228
73
81
Munson Ranch #9H(6)
1,700
7
13,756
123
393
400
184
202
Rock Creek Ranch #3H(6)
1,903
9
12,886
58
341
384
248
284
Rock Creek Ranch #4H(6)
2,403
10
21,407
54
243
291
379
451
Rock Creek Ranch #9H
WOC
Schacherl #1H(5)
Drilling
Rock Creek Ranch #10H
Drilling
?
?
(4)
Wellhead rates only; the natural gas associated with these wells is yielding approximately 145 barrels of NGLs per million cubic feet (MMcf).
(5)
Wells located in Lavaca County; all other wells are located in Gonzales County.
(6)
The Cannonade Ranch #3H had been shut-in to address H2S production issues, while the Munson Ranch #9H, Rock Creek Ranch #3H and #4H had short laterals and fewer frac stages. As a result, production data for these four wells has been excluded from the statistics.
?
Full-Year 2012 Guidance
Full-year 2012 guidance highlights are as follows:
Full-year 2012 production is expected to be 40.0 to 43.0 Bcfe, unchanged from previous guidance
Crude oil and liquids are expected to comprise approximately 43 ?percent of total production during 2012
Full-year 2012 product revenues are expected to be $292 to $316 million, compared to $288 to $319 million of previous guidance, excluding the impact of our hedges
Crude oil and NGL product revenues are expected to be approximately 84 percent of total product revenues during 2012
Approximately 70 percent of estimated crude oil production volumes and 25 percent of estimated natural gas production volumes are hedged over the remaining three quarters of 2012 at weighted average prices of $102.21 per barrel and $5.27 per Mcf, respectively
2012 settlements of current commodity hedges are expected to result in cash receipts of approximately $28 ?million
Full-year 2012 Adjusted EBITDAX, a non-GAAP measure, is expected to be $220 to $240 million, compared to previous guidance of $200 to $240 million
Full-year 2012 cash flow from operating activities is expected to be $185 to $205 million, compared to previous guidance of $175 to $205 million (both ranges include an anticipated $30 million income tax refund in the fourth quarter of 2012)
Full-year 2012 capital expenditures are expected to be $300 to $325 ?million, unchanged from previous guidance
Approximately 89 percent of the 2012 capital expenditures are expected to be allocated to the Eagle Ford Shale and approximately four percent to the Mid-Continent
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.
Capital Resources and Liquidity, Interest Expense and Impact of Derivatives
As of March 31, 2012, we had total debt with a carrying value of approximately $718 million ($724 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, $5 ?million principal amount of 4.5 ?percent convertible senior subordinated notes due 2012 (classified as a current liability) and $119 million of borrowings under our revolving credit facility (Revolver). Our indebtedness at March 31, 2012 was approximately 46 ?percent of book capitalization and 3.0 times the latest twelve months′ Adjusted EBITDAX of $242.7 ?million, a reduction from 3.2 times at year-end 2011.
We have no material debt maturities until 2016. Our business strategy for 2012 requires capital expenditures in excess of our anticipated operating cash flows, although within the Revolver′s borrowing base, as shown in the table below.
?
?
Year Ending December 31, 2012
Guidance Range
In millions
Low
?
?
High
?
Net cash provided by operating activities (7)
$
185.0
$
205.0
Less: Common stock dividends
(10.3
)
(10.3
)
Less: Repayment of 4.5 percent convertible senior subordinated notes due December 2012
(4.9
)
(4.9
)
Less: Capitalized interest
?
(2.0
)
?
(2.0
)
Cash flows available for investment
$
167.8
$
187.8
Less: Capital expenditures (including seismic expenditures)
(325.0
)
(300.0
)
Plus: Seismic expenditures (included in cash flows from operating activities)
?
10.0
?
?
5.0
?
Capital outspend of cash flows
$
(147.2
)
$
(107.2
)
?
?
(7)
Please see the Guidance Table included in this release for guidance estimates for full-year 2012, which include production of 40.0 to 43.0 Bcfe (6.7 to 7.2 million BOE) and average benchmark prices of $95.75 per barrel for crude oil, $42.29 per barrel for NGLs and $2.40 per MMBtu for natural gas, adjusted to reflect any premium or discount for quality, basin differentials and other adjustments. In addition, cash flows from operating activities include an estimated $30 million cash income tax refund expected to be received in the fourth quarter of 2012.
?
We plan to fund our 2012 capital program with operating cash flows, proceeds from asset sales and borrowings under the Revolver.
Borrowing Base Redetermination
In August 2011, we entered into the Revolver, which matures in August 2016. The Revolver provided for a $300 ?million commitment amount and initial borrowing base of $380 million. Following the semi-annual redetermination in April 2012 and as a result of decreased natural gas prices, the borrowing base was lowered to $300 million, which is at the upper end of our previously disclosed expectations. Our business plan anticipates us borrowing amounts under the Revolver during the remainder of 2012 that are within this redetermined borrowing base. As of April 30, 2012, we had approximately $22 million of cash on hand and approximately $151 ?million of unused borrowing capacity under the Revolver, net of outstanding letters of credit of $1.7 ?million.
Planned Asset Sale
We expect to reduce our indebtedness and supplement liquidity under the Revolver with proceeds from the sale of non-core assets. We recently engaged a financial advisor to assist us in the sale of the majority of our remaining Mid-Continent assets. The sales process for these liquids-rich and largely non-operated properties has commenced. The properties anticipated to be sold include our Granite Wash production and reserves, as well as a few exploratory prospects. However, we will retain our Viola Limestone prospect acreage, which we expect to drill late in the second quarter of this year. Based on internal estimates, the properties to be divested have proved reserves of approximately 123 Bcfe, 46 ?percent of which are NGLs and oil, and 81 gross remaining drilling locations. First quarter 2012 production for these assets was 23.6 ?MMcfe per day, 48 percent of which was NGLs and oil. No assurances can be given that a sale will be completed or as to the timing of or the net proceeds from such a sale.
Explanation of Non-GAAP Gross Operating Margin per Mcfe
Gross operating margin is a non-GAAP financial measure under 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.
First Quarter 2012 Financial and Operational Results Conference Call
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
March 31,
2012
2011
Revenues
Natural gas
$
14,886
$
41,189
Crude oil
58,723
16,583
Natural gas liquids (NGLs)
?
9,071
?
?
9,921
?
Total product revenues
82,680
67,693
Gain on sales of property and equipment
756
480
Other
?
975
?
?
410
?
Total revenues
84,411
68,583
Operating expenses
Lease operating
9,143
10,277
Gathering, processing and transportation
4,154
4,028
Production and ad valorem taxes
3,580
5,064
General and administrative (excluding share-based compensation)
?
10,526
?
?
11,556
?
Total direct operating expenses
27,403
30,925
Share-based compensation (a)
1,615
1,796
Exploration
7,998
29,548
Depreciation, depletion and amortization
?
50,817
?
?
34,843
?
Total operating expenses
?
87,833
?
?
97,112
?
?
Operating loss
(3,422
)
(28,529
)
?
Other income (expense)
Interest expense
(14,774
)
(13,484
)
Derivatives
(305
)
1,328
Other
?
1
?
?
144
?
?
Loss before income taxes
(18,500
)
(40,541
)
Income tax benefit
?
6,601
?
?
14,201
?
?
Net loss
$
(11,899
)
$
(26,340
)
?
Loss per share:
Basic
$
(0.26
)
$
(0.58
)
Diluted
$
(0.26
)
$
(0.58
)
?
Weighted average shares outstanding, basic
45,945
45,687
Weighted average shares outstanding, diluted
45,945
45,687
?
?
?
?
?
?
?
?
?
?
?
?
Three months ended
March 31,
2012
2011
Production
Natural gas (MMcf)
6,294
9,726
Crude oil (MBbls)
549
188
NGLs (MBbls)
215
220
Total natural gas, crude oil and NGL production (MMcfe)
10,874
12,171
?
Prices
Natural gas ($ per Mcf)
$
2.37
$
4.23
Crude oil ($ per Bbl)
$
107.05
$
88.37
NGLs ($ per Bbl)
$
42.24
$
45.11
?
Prices - Adjusted for derivative settlements
Natural gas ($ per Mcf)
$
3.65
$
4.95
Crude oil ($ per Bbl)
$
106.85
$
87.17
NGLs ($ per Bbl)
$
42.24
$
45.11
?
(a) Our 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. Share-based compensation expense related to liability-classified awards payable in cash is included in general and administrative expense.
?
PENN VIRGINIA CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS - unaudited
(in thousands)
?
?
?
?
As of
March 31,
?
?
December 31,
2012
2011
Assets
Current assets
$
128,546
$
145,346
Net property and equipment
1,809,291
1,777,575
Other assets
?
20,866
?
?
20,132
?
Total assets
$
1,958,703
?
$
1,943,053
?
?
Liabilities and shareholders' equity
Current liabilities (a)
$
119,634
$
106,607
Revolving credit facility
119,000
99,000
Senior notes due 2016
293,848
293,561
Senior notes due 2019
300,000
300,000
Other liabilities and deferred income taxes
292,760
297,576
Total shareholders' equity
?
833,461
?
?
846,309
?
Total liabilities and shareholders' equity
$
1,958,703
?
$
1,943,053
?
?
?
?
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - unaudited
(in thousands)
?
?
Three months ended
March 31,
2012
2011
Cash flows from operating activities
Net loss
$
(11,899
)
$
(26,340
)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization
50,817
34,843
Derivative contracts:
Net losses (gains)
305
(1,328
)
Cash settlements
7,981
6,744
Deferred income tax benefit
(6,601
)
(14,201
)
Gain on the sales of property and equipment, net
(756
)
(480
)
Non-cash exploration expense
8,171
26,999
Non-cash interest expense
1,015
3,272
Share-based compensation
1,615
1,796
Other, net
56
236
Changes in operating assets and liabilities
?
19,997
?
?
(2,105
)
Net cash provided by operating activities
?
70,701
?
?
29,436
?
Cash flows from investing activities
Capital expenditures - property and equipment
(94,469
)
(100,729
)
Proceeds from the sales of property, plant and equipment, net
778
360
Other, net
?
-
?
?
100
?
Net cash used in investing activities
?
(93,691
)
?
(100,269
)
Cash flows from financing activities
Dividends paid
(2,586
)
(2,576
)
Proceeds from revolving credit facility borrowings
23,000
-
Repayment of revolving credit facility borrowings
(3,000
)
-
Other, net
?
-
?
?
838
?
Net cash provided by (used in) financing activities
?
17,414
?
?
(1,738
)
Net decrease in cash and cash equivalents
(5,576
)
(72,571
)
Cash and cash equivalents - beginning of period
?
7,512
?
?
120,911
?
Cash and cash equivalents - end of period
$
1,936
?
$
48,340
?
?
Supplemental disclosures of cash paid for:
Interest (net of amounts capitalized)
$
557
$
387
Income taxes (net of refunds received)
$
(301
)
$
(120
)
?
(a) The convertible notes are due in November 2012 and are included in current liabilities.
?
PENN VIRGINIA CORPORATION
CERTAIN NON-GAAP FINANCIAL MEASURES - unaudited
(in thousands)
?
?
?
?
?
Three months ended
March 31,
2012
2011
Reconciliation of GAAP 'Net loss' to Non-GAAP 'Net loss, as adjusted'
Net loss
$
(11,899
)
$
(26,340
)
Adjustments for derivatives:
Net losses (gains) included in net loss
305
(1,328
)
Cash settlements
7,981
6,744
Adjustment for restructuring costs
-
18
Adjustment for net loss (gain) on sale of assets
(756
)
(480
)
Impact of adjustments on income taxes
?
(2,687
)
?
(1,735
)
Net loss, as adjusted (a)
$
(7,056
)
$
(23,121
)
?
Net loss, as adjusted, per share, diluted
$
(0.15
)
$
(0.51
)
?
Reconciliation of GAAP 'Net loss' to Non-GAAP 'Adjusted EBITDAX'
Net loss
$
(11,899
)
$
(26,340
)
Income tax benefit
(6,601
)
(14,201
)
Interest expense
14,774
13,484
Depreciation, depletion and amortization
50,817
34,843
Exploration
7,998
29,548
Share-based compensation expense
?
1,615
?
?
1,796
?
EBITDAX
56,704
39,130
Adjustments for derivatives:
Net gains included in net income
305
(1,328
)
Cash settlements
7,981
6,744
Adjustment for net loss (gain) on sale of assets
?
(756
)
?
(480
)
Adjusted EBITDAX (b)
$
64,234
?
$
44,066
?
?
(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.
?
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 2012. These estimates are meant to provide guidance only and are subject to change as PVA's operating environment changes.
?
?
?
?
First
Quarter
Full-Year
2012
2012 Guidance
Production:
?
?
?
?
?
Natural gas (Bcf)
6.3
23.0
-
24.4
Crude oil (MBbls)
549
2,100
-
2,275
NGLs (MBbls)
215
733
-
825
Equivalent production (Bcfe)
10.9
40.0
-
43.0
Equivalent daily production (MMcfe per day)
119.5
109.3
-
117.8
Equivalent production (MBOE)
1,812
6,667
-
7,167
Equivalent daily production (MBOE per day)
19.9
18.2
-
19.6
Percent crude oil and NGLs
42.1
%
42.5
%
-
43.3
%
?
Production revenues (a):
Natural gas
$
14.9
46.0
-
51.0
Crude oil
$
58.7
214.0
-
230.0
NGLs
$
9.1
32.0
-
35.0
Total product revenues
$
82.7
292.0
-
316.0
Total product revenues ($ per Mcfe)
$
7.60
7.30
-
7.35
Total product revenues ($ per BOE)
$
45.62
43.80
-
44.09
Percent crude oil and NGLs
$
82.0
%
82.5
%
-
85.4
%
?
Operating expenses:
Lease operating ($ per Mcfe)
$
0.84
0.80
-
0.85
Lease operating ($ per BOE)
$
5.04
4.80
-
5.10
Gathering, processing and transportation costs ($ per Mcfe)
$
0.38
0.31
-
0.36
Gathering, processing and transportation costs ($ per BOE)
$
2.29
1.86
-
2.16
Production and ad valorem taxes (percent of oil and gas revenues)
4.3
%
4.0
%
-
4.5
%
?
General and administrative:
Recurring general and administrative
$
10.5
39.0
-
41.0
Share-based compensation
$
1.6
6.5
-
7.0
Restructuring
$
-
Total reported G&A
$
12.1
45.5
-
48.0
?
Total reported exploration
$
8.0
43.0
-
46.0
Unproved property amortization
$
8.2
35.0
-
36.0
?
Depreciation, depletion and amortization ($ per Mcfe)
$
4.67
4.75
-
5.00
Depreciation, depletion and amortization ($ per BOE)
$
28.04
28.50
-
30.00
?
Adjusted EBITDAX (b)
$
64.2
220.0
-
240.0
Net cash provided by operating activities (c)
$
70.7
185.0
-
205.0
?
Capital expenditures:
Drilling and completion
$
82.6
265.0
275.0
Pipeline, gathering, facilities
$
3.9
10.0
-
15.0
Seismic (d)
$
(0.4
)
5.0
-
10.0
Lease acquisitions, field projects and other
$
4.3
20.0
-
25.0
Total oil and gas capital expenditures
$
90.4
300.0
-
325.0
?
End of period debt outstanding
$
717.6
Effective interest rate
8.5
%
Income tax benefit rate
35.7
%
38.0
%
?
-
?
39.0
%
(a) Assumes average benchmark prices of $95.75 per barrel for crude oil, $42.29 per barrel for NGLs and $2.40 per MMBtu for natural gas, prior to any premium or discount for quality, basin differentials, the impact of hedges and other adjustments.
(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 from continuing operations.
(c) Includes an estimated $30 million cash income tax refund expected to be received in the fourth quarter of 2012.
(d) Seismic expenditures are also reported as a component of exploration expense and as a component of net cash provided by operating activities from continuing operations.
?
?
PENN VIRGINIA CORPORATION
GUIDANCE TABLE - unaudited - (continued)
?
?
Note to Guidance Table:
?
?
?
?
The following table shows our current derivative positions.
?
Weighted Average Price
Average Volume
Instrument Type
Per Day
Floor/ Swap
Ceiling
?
Natural gas:
(MMBtu)
($ / MMBtu)
Second quarter 2012
Swaps
20,000
5.31
Third quarter 2012
Swaps
20,000
5.31
Fourth quarter 2012
Swaps
10,000
5.10
?
Crude oil:
(barrels)
($ / barrel)
Second quarter 2012
Collars
1,000
90.00
97.00
Third quarter 2012
Collars
1,000
90.00
97.00
Fourth quarter 2012
Collars
1,000
90.00
97.00
First quarter 2013
Collars
1,000
90.00
100.00
Second quarter 2013
Collars
1,000
90.00
100.00
Third quarter 2013
Collars
1,000
90.00
100.00
Fourth quarter 2013
Collars
1,000
90.00
100.00
Second quarter 2012
Swaps
3,000
103.05
Third quarter 2012
Swaps
3,000
104.40
Fourth quarter 2012
Swaps
3,000
104.40
First quarter 2013
Swaps
2,250
103.51
Second quarter 2013
Swaps
2,250
103.51
Third quarter 2013
Swaps
1,500
102.77
Fourth quarter 2013
Swaps
1,500
102.77
First quarter 2014
Swaps
2,000
100.44
Second quarter 2014
Swaps
2,000
100.44
Third quarter 2014
Swaps
1,500
100.20
Fourth quarter 2014
Swaps
1,500
100.20
First quarter 2013
Swaption
1,100
100.00
Second quarter 2013
Swaption
1,000
100.00
Third quarter 2013
Swaption
900
100.00
Fourth quarter 2013
Swaption
750
100.00
First quarter 2014
Swaption
812
100.00
Second quarter 2014
Swaption
812
100.00
Third quarter 2014
Swaption
812
100.00
Fourth quarter 2014
Swaption
812
100.00
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 remainder of 2012 would increase or decrease by approximately $17 million. In addition, we estimate that for every $10.00 per barrel increase or decrease in the crude oil price, operating income for the remainder of 2012 would increase or decrease by approximately $15 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.