Exhibit 99.1

Penn Virginia Reports Fourth Quarter and Year-End 2017 Results, Provides

Operational Update and Closes Previously Announced Acquisition

— Strong Results in Area 2 from 2 Well Pad with IP Rate of Over 5,000 BOEPD —

— Grew Proved Reserves by 47%, Replaced 710% of 2017 Production —

— Expects 2018 Production Growth of ~125% —

HOUSTON, March 1, 2018 (GLOBE NEWSWIRE) — Penn Virginia Corporation (“Penn Virginia” or the “Company”) (NASDAQ:PVAC) today announced its financial and operational results for the fourth quarter and full year 2017, and year-end reserve estimates.

Significant Operational Accomplishments

 

  Strong well results in Area 2 – the two-well Geo Hunter pad had a 30-day initial production (“IP”) rate of 3,767 barrels of oil equivalent per day (“BOEPD”) and a previously announced 24-hour IP rate of 5,465 BOEPD. In addition, the Company recorded a 24-hour IP rate from its Southern Hunter Amber two-well pad of 5,092 BOEPD. Both pads utilized the Company’s slickwater completion design;

 

  Produced 3.8 million barrels of oil equivalent (“MMBOE”), or 10,353 BOEPD (73% crude oil), for full year 2017, including 12,340 BOEPD (74% crude oil) in the fourth quarter of 2017 – a 32% increase over the fourth quarter of 2016. Achieved a 2017 exit rate (average of last five days of 2017) of approximately 14,650 BOEPD. Targeting year-over-year production growth of ~125%(1) for 2018 under its current development program;

 

  Increased proved reserves by approximately 47% to 72.6 MMBOE (85 MMBOE pro forma for the Hunt acquisition discussed below), representing 710% of 2017 production at a drill-bit finding and development cost of approximately $4.40 per barrel of oil equivalent (“BOE”)(2);

 

  Increased drilling locations at year-end (pro forma for the Hunt acquisition) to 500 net (589 gross), of which approximately 80 net locations (100 gross) are higher rate of return extended reach laterals (“XRLs”) (12 in Area 1 and 68 in Area 2), which provides the underpinning for the Company’s 2018 development program; and

 

  Closed the previously announced acquisition of Eagle Ford assets located primarily in Gonzales and Lavaca Counties, Texas, from Hunt Oil Company (“Hunt”) on March 1, 2018.

Financial Highlights

 

  Incurred a net loss of $10.8 million, or $0.72 per diluted share, in the fourth quarter of 2017. Adjusted net income(3) was $15.8 million, or $1.06 per diluted share, in the fourth quarter of 2017. Net income was $32.7 million, or $2.17 per diluted share, for the full year 2017. Adjusted net income(3) was $43.4 million, or $2.88 per diluted share, for the full year 2017;

 

  Generated adjusted EBITDAX(4) of $37.4 million in the fourth quarter of 2017, up 78% over the fourth quarter of 2016, or approximately $32.97 per BOE. For the full year 2017, the Company generated adjusted EBITDAX(4) of $102.2 million, or approximately $27.05 per BOE; and

 

  Increased the borrowing base under its credit facility by more than 40% to $340 million, effective March 1, 2018. Current availability under the credit facility is $164.2 million.


  (1) Assumes mid-point of production guidance.
  (2) For an explanation of these supplemental measures, see the section titled “Reserve Replacement Ratio and Drill-bit Finding and Development - Definition” at the end of this release.
  (3) Adjusted net income is a non-GAAP financial measure. Definitions of non-GAAP financial measures and reconciliations of non-GAAP financial measures to the closest GAAP-based financial measures appear at the end of this release.
  (4) Adjusted EBITDAX is a non-GAAP financial measure. Definitions of non-GAAP financial measures and reconciliations of non-GAAP financial measures to the closest GAAP-based financial measures appear at the end of this release.

“2017 was a very successful year,” commented John A. Brooks, President and Chief Executive Officer of Penn Virginia. “We increased production in the fourth quarter by more than 30% over the fourth quarter of 2016, grew adjusted EBITDAX by 78% over the same period, significantly increased proved reserves, executed two strategic acquisitions that increased our drilling inventory.”

Mr. Brooks added, “We are off to a terrific start in 2018. We entered the year with a production rate that was 19% higher than the fourth quarter average, driven by the strong performance of the Geo Hunter pad. We also recently turned to sales our latest confirmation of slickwater completions in Area 2, the two-well Southern Hunter Amber pad, and are excited about the strong initial performance from these two wells. Additionally, we have expanded our technical team and upgraded our drilling and completion equipment and are seeing dramatic improvements in cycle times and performance. As a result of this improved operational execution of our current drilling program, along with the Devon and Hunt acquisitions, we are targeting fiscal 2018 production growth of approximately 125% over full year 2017 levels. With the anticipated higher production levels, we expect to see a material increase in our cash flow, thereby further strengthening our balance sheet and positioning the Company for additional growth and success.”

Fourth Quarter 2017 Operating Results

Total production in the fourth quarter of 2017 increased approximately 32% from the fourth quarter of 2016, to 1,135 thousand barrels of oil equivalent (“MBOE”), or 12,340 BOEPD (74% crude oil). At year-end, the Company’s exit rate (average of last five days of 2017) was approximately 14,650 BOEPD.

Penn Virginia drilled and turned to sales nine gross (5.3 net) wells during the fourth quarter of 2017, all in the Eagle Ford. At year-end, Penn Virginia turned to sales the Geo Hunter pad, which had a 24-hour IP rate of 5,465 BOEPD, or 394 BOEPD per 1,000 feet of lateral. For the IP 30-day, the well produced 3,767 BOEPD, or 271 BOEPD per 1,000 feet of lateral. As a result of the Devon acquisition, which closed in the third quarter of 2017, the Company holds a 93.2% working interest. In early February, Penn Virginia turned to sales the Southern Hunter Amber (“SHA”) pad in Area 2. On average, the SHA wells were completed with lateral lengths of approximately 8,100 feet. The SHA pad recorded a combined 24-hour IP rate of 5,092 BOEPD or 314 BOEPD per 1,000 feet of lateral. The Company has a 98.1% working interest. Both the Geo Hunter and SHA pads were Area 2 slickwater completions.

The table below shows the current status of Eagle Ford pads that are either completing, waiting on completion, or drilling:

 

Pad Name

   Working
Interest
    Status    Area 1/2
Elk Hunter 3 Well      74   Drilling    1
Lott 3 Wells      100   Drilling    2
Snipe Hunter 3 Wells      80   Drilling    1
Dubose 3 Wells      83   Completing    1
Bongo Hunter 3 Wells      82   Completing    1
Schacherl Effeinberger 2 Wells      71   Waiting on Completion    2
McCreary-Technik 3Wells      74   Waiting on Completion    2
Medina 3 Wells      100   Waiting on Completion    2


At year-end 2017, Penn Virginia held approximately 73,400 net acres in the Eagle Ford, net of expirations. Pro forma for the Hunt acquisition, the Company had approximately 83,100 net Eagle Ford acres with 39,100 in Area 1 and 44,000 in Area 2.

Penn Virginia at year-end (pro forma for the Hunt acquisition discussed below) had an estimated 589 gross (500 net) drilling locations of which 99% are Company-operated and 100 gross (80 net) are anticipated to be XRLs. Approximately 93% of Penn Virginia’s core acreage is held by production.

Year-End 2017 Proved Reserves

Penn Virginia’s total proved reserves as of December 31, 2017 increased approximately 47% to 72.6 MMBOE (pro forma for the Hunt acquisition, 85 MMBOE) compared to 49.5 MMBOE reported at year-end 2016. The composition of the reserves at the end of 2017 was 77% oil, 12% NGLs and 11% natural gas, with 44% of the reserves classified as proved developed. Penn Virginia’s independent reserve engineering firm, DeGolyer and MacNaughton, Inc., completed its estimate of the Company’s year-end 2017 proved reserves in accordance with Securities and Exchange Commission (SEC) guidelines using pricing of $51.34 per barrel for crude oil and $2.98 per million British Thermal Units (MMBtu) for natural gas, which in each case was 20% higher than year end 2016 SEC oil and natural gas pricing.

The Company’s standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves (“Standardized Measure”) was $590.5 million as of December 31, 2017, compared to $317.6 million as of year-end 2016. The increase in the Standardized Measure of the Company’s proved reserves was primarily a result of an increase in proved reserves and the average NYMEX oil and natural gas price. The value of the Company’s total proved reserves, utilizing the SEC price guidelines, discounted at 10% and before tax (“PV-10 value”)(1), was $609.0 million as of December 31, 2017. The PV-10 value of the Company’s total proved developed producing (PDP) reserves utilizing the SEC price guidelines was $442.2 million as of December 31, 2017(1). Using strip pricing at December 31, 2017 (disclosed in the Appendix of this release), the PV-10 value of the Company’s total proved reserves and PDP reserves was $681.2 million and $482.2 million, respectively.

 

  (1) PV-10 value is a non-GAAP measure reconciled to Standardized Measure in the Appendix of this release.


The table below summarizes the changes in the Company’s proved reserves during 2017:

 

                 Natural     Total  
Proved    Oil     NGL     Gas     Equivalents  
Reserves    (MBbls)     (MBbls)     (MMcf)     (Mboe)  

Beginning Reserves (December 31, 2016)

     36,611       6,765       36,682       49,490  

Production

     (2,764     (523     (2,949     (3,779

Revisions to Previous Estimates

     (5,735     (2,071     (10,468     (9,550

Extensions and Discoveries

     23,850       3,571       16,840       30,228  

Purchase of Reserves

     3,867       1,122       7,162       6,183  

Sale of Reserves in Place

     —         —         —         —    
  

 

 

   

 

 

   

 

 

   

 

 

 

Ending Reserves (December 31, 2017)

     55,829       8,864       47,267       72,572  
  

 

 

   

 

 

   

 

 

   

 

 

 
  

 

 

   

 

 

   

 

 

   

 

 

 

Proved Developed Reserves

     22,412       4,882       27,229       31,832  

Fourth Quarter 2017 Financial Results

Total direct operating expenses, which consist of lease operating expense (“LOE”), gathering, processing and transportation (“GPT”) expense, severance and ad valorem taxes, and cash general and administrative (“G&A”) expense, were $14.9 million, or $13.11 per BOE, in the fourth quarter of 2017 as compared to $12.7 million, or $14.81 per BOE, in the fourth quarter of 2016.

Net loss for the fourth quarter of 2017 was $10.8 million, or $0.72 loss per diluted share, compared to net loss of $1.9 million, or $0.12 per diluted share, in the fourth quarter of 2016. Adjusted net income(1) was $15.8 million, or $1.06 per diluted share in the fourth quarter of 2017, versus $10.7 million, or $0.71 per diluted share in the fourth quarter of 2016.

Adjusted EBITDAX(2) was $37.4 million in the fourth quarter of 2017, a 78% increase from the fourth quarter of 2016. Adjusted EBITDAX per BOE for the fourth quarter of 2017 was $32.97.

 

(1) Adjusted net income is a non-GAAP financial measure. Definitions of non-GAAP financial measures and reconciliations of non-GAAP financial measures to the closest GAAP-based financial measures appear at the end of this release.
(2) Adjusted EBITDAX is a non-GAAP financial measure. Definitions of non-GAAP financial measures and reconciliations of non-GAAP financial measures to the closest GAAP-based financial measures appear at the end of this release.

Full Year 2017 Financial Results

Total direct operating expenses were $55.8 million, or $14.76 per BOE in 2017.

Net income for the full year of 2017 was $32.7 million, or $2.17 per diluted share. Adjusted net income was $43.4 million, or $2.88 per diluted share in 2017(1).

Adjusted EBITDAX(2) was $102.2 million for 2017, or approximately $27.05 per BOE.

 

  (1) Adjusted net income is a non-GAAP financial measure. Definitions of non-GAAP financial measures and reconciliations of non-GAAP financial measures to the closest GAAP-based financial measures appear at the end of this release.
  (2) Adjusted EBITDAX is a non-GAAP financial measure. Definitions of non-GAAP financial measures and reconciliations of non-GAAP financial measures to the closest GAAP-based financial measures appear at the end of this release.


Hunt Acquisition

On March 1, 2018, Penn Virginia closed the previously announced acquisition of assets in the Eagle Ford Shale, primarily in Gonzales and Lavaca Counties, from Hunt for $86 million in cash, subject to adjustments. The acquisition provides proved reserves of approximately 12 MMBOE, of which approximately 86% is oil, and provides total resource potential of more than 29 MMBOE. The effective date of the acquisition is October 1, 2017.

Hedging Update

Penn Virginia enters into oil hedges on a portion of its production to help mitigate commodity price risk.

The table below sets forth Penn Virginia’s current oil hedge positions:

 

     WTI – Oil
Volumes
(Barrels Per Day)
     WTI - Average
Swap Price

($/barrel)
     LLS - Oil
Volumes
(Barrels Per Day)
     LLS - Average
Swap Price

($/barrel)
     Percent of
Oil Production
Hedged (1)
 

2018

     6,227      $ 50.70        2,500      $ 55.18        50

2019

     4,915      $ 52.12        2,500      $ 51.30        —    

2020

     4,000      $ 52.67        —          —          —    

 

(1) Assumes mid-point of oil guidance.

Balance Sheet and Liquidity

During the fourth quarter of 2017, the Company incurred $55.7 million of capital expenditures (excluding acquisitions), of which 95% was associated with drilling and completion capital. For the full year 2017, Penn Virginia incurred $133.0 million of capital expenditures (excluding acquisitions), of which 94% was for drilling and completion capital.

On March 1, 2018, concurrent with the closing of the Hunt acquisition, the Company’s borrowing base increased more than 40% to $340 million from $237.5 million. The new borrowing base includes reserve value purchased in the Hunt acquisition along with wells drilled since the last redetermination.

As of December 31, 2017, Penn Virginia had $77.0 million outstanding on its credit facility and liquidity of $170.7 million. As of March 1, 2018, following the closing of the Hunt acquisition, the Company had outstanding borrowings of $175.0 million, resulting in $164.2 million available under the credit facility.

The Company is committed to maintaining financial discipline and a strong balance sheet with a targeted net debt to EBITDAX ratio (as referenced in the Company’s credit agreement) of 1.5x or below. Penn Virginia believes it will achieve its leverage target by the end of 2018 and spend within cash flow by the fourth quarter of 2018. As of December 31, 2017, pro forma for the Hunt acquisition, the Company’s net debt to Adjusted EBITDAX ratio(1) was approximately 2.6x.

 

  (1) As defined in the Company’s credit facility.


2018 Capital Plans

Capital expenditures for 2018 are expected to total between $320 and $360 million, with 95% of capital being directed to drilling and completions in the Eagle Ford. The capital plan provides for drilling a total of 55 to 60 gross wells (45 to 50 net). Penn Virginia plans to drill between 33 to 35 gross wells (26 to 28 net) in Area 1 and to drill between 22 to 25 gross wells (19 to 22 net) in Area 2. In 2018, the Company expects to drill 22 XRL wells. Penn Virginia plans to fund its 2018 capital plans with cash flow from operations and borrowing under its credit facility.

Guidance

The table below sets forth the Company’s operational and financial guidance for 2018:

 

     2018        

Production (BOEPD)

       % oil  

First Quarter

     15,500 - 16,500       74

Full Year

     22,000 - 25,000       74

Realized Price Differentials

    

Oil (off WTI, per barrel)

   $ 1.00 - $2.00    

Natural gas (off Henry Hub, per MMBtu)

   $ 0.10 - $0.20    

Direct Operating Expenses

    

Lease operating expense (per BOE)

   $ 4.75 - $5.25    

GPT expense (per BOE)

   $ 2.75 - $3.00    

Ad valorem and production taxes (percent of product revenue)

     5.5% - 6.0  

Cash G&A expense (per BOE)

   $ 2.25 - $2.75    

Capital Expenditures (millions)

   $ 320 - $360    

Fourth Quarter 2017 Conference Call

A conference call and webcast discussing fourth quarter and full-year 2017 financial and operational results is scheduled for Friday, March 2, 2018 at 11:00 a.m. EDT. Prepared remarks will be followed by a question and answer period. Investors and analysts may participate via phone by dialing (877) 316-5288 (international: (734) 385-4977) five to 10 minutes before the scheduled start time, or via webcast by logging on to the Company’s website, www.pennvirginia.com, at least 15 minutes prior to the scheduled start time to download supporting materials and install any necessary audio software.

An on-demand replay of the webcast will also be available on the Company’s website beginning shortly after the webcast. The replay will also be available from March 2, 2018 through March 9, 2018 by dialing (855) 859-2056 (international (404) 537-3406) and entering the pass code 2189937.

About Penn Virginia Corporation

Penn Virginia Corporation 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 the Eagle Ford Shale in south Texas. For more information, please visit our website at www.pennvirginia.com.


Cautionary Statements Regarding Reserves

The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that a company anticipates as of a given date to be economically and legally producible and deliverable by application of development projects to known accumulations. We use certain terms in this news release, such as total resource potential, that the SEC’s rules strictly prohibit us from including in filings with the SEC. These measures are by their nature more speculative than estimates of reserves prepared in accordance with SEC definitions and guidelines and accordingly are less certain. We also note that the SEC strictly prohibits us from aggregating proved, probable and possible reserves (3P) in filings with the SEC due to the different levels of certainty associated with each reserve category.

The estimates and guidance presented in this release are based on assumptions of capital expenditure levels, prices for oil, natural gas and NGLs, current indications of supply and demand for oil, well results and operating costs. IP-24 production results might not be indicative of production over longer periods in the life of the well. Data regarding acreage that is expected to be acquired is based on currently available information about such acreage, including reserves and production, that was provided to us by third parties. The guidance provided in this release does not constitute any form of guarantee or assurance that the matters indicated will be achieved. While we believe these estimates and the assumptions on which they are based are reasonable, they are inherently uncertain and are subject to, among other things, significant business, economic, operational and regulatory risks and uncertainties and are subject to material revision. Actual results may differ materially from estimates and guidance.

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. We use words such as “guidance,” “projects,” “estimates,” “expects,” “continues,” “intends,” “plans,” “believes,” “forecasts,” “future,” and variations of such words or similar expressions in this press release to identify forward-looking statements. Because such statements include assumptions, 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: risks related to the recently completed acquisitions, including the Company’s ability to realize their expected benefits; our ability to satisfy our short-term and long-term liquidity needs, including our ability to generate sufficient cash flows from operations or to obtain adequate financing to fund our capital expenditures and meet working capital needs; negative events or publicity adversely affecting our ability to maintain our relationships with our suppliers, service providers, customers, employees, and other third parties; plans, objectives, expectations and intentions contained in this press release that are not historical; our ability to execute our business plan in volatile and depressed commodity price environments; any decline in and volatility of commodity prices for oil, NGLs, and natural gas; our anticipated production and development results; 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; our ability to contract for drilling rigs, frac crews, 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 that estimated in our proved oil and natural gas reserves; drilling and operating risks; concentration of assets; our ability to compete effectively against other oil and gas companies; leasehold terms expiring before production can be established and our ability to replace expired leases; costs or results of any strategic initiatives; environmental obligations, results of new drilling activities, locations and methods, 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; and counterparty risk related to the ability of parties to these arrangements to meet their future obligations; the occurrence of unusual weather or operating conditions, including force majeure events and hurricanes; our ability to retain or attract senior management and key employees; potential adverse effects of the completed bankruptcy proceedings on our liquidity, results of operations, business prospects, ability to retain financing and other risks and uncertainties related to our emergence from bankruptcy; our post-bankruptcy capital structure and the adoption of fresh start accounting, including the risk that assumptions and factors used in estimated enterprise value vary significantly from the current estimates in connection with the application of fresh start accounting; compliance with and changes in governmental regulations or enforcement practices, especially with respect to environmental, health and safety matters; physical, electronic and cybersecurity breaches; litigation that impacts us, our assets or our midstream service providers; 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 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. The statements in this release speak only as of the date of this release. 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, except as may be required by applicable law.

Contact

Steve Hartman

Chief Financial Officer

Ph: (713) 722-6529

E-Mail: invest@pennvirginia.com


PENN VIRGINIA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS and SELECTED OPERATING STATISTICS- unaudited

(in thousands, except per share data, production and price)

 

     Successor     Successor     Successor     Successor     Successor     Predecessor  
     Three Months
Ended
December 31,
    Three Months
Ended
September 30,
    Three Months
Ended
December 31,
    Year
Ended
December 31,
    September 13
Through
December 31,
    January 1
Through
September 12,
 
     2017     2017     2016     2017     2016     2016  

Revenues

            

Crude oil

   $ 48,499     $ 29,963     $ 27,649     $ 140,886     $ 33,157     $ 81,377  

Natural gas liquids (NGLs)

     3,328       2,393       2,374       10,066       2,707       6,064  

Natural gas

     2,317       1,977       2,315       8,517       2,790       6,208  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total product revenues

     54,144       34,333       32,338       159,469       38,654       93,649  

Gain (loss) on sales of assets, net

     24       9       (49     (36     (49     1,261  

Other, net

     159       117       365       621       398       (600
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

     54,327       34,459       32,654       160,054       39,003       94,310  

Operating expenses

            

Lease operating

     6,244       5,254       4,575       21,784       5,331       15,626  

Gathering, processing and transportation

     3,229       2,399       2,467       10,734       3,043       13,235  

Production and ad valorem taxes

     3,048       1,668       2,123       8,814       2,498       3,490  

General and administrative

     2,360       5,939       3,531       14,453       5,007       37,434  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total direct operating expenses

     14,881       15,260       12,696       55,785       15,879       69,785  

Share-based compensation - equity classified awards

     1,102       1,013       81       3,809       81       1,511  

Exploration

     —         —         —         —         —         10,288  

Depreciation, depletion and amortization

     17,104       10,659       9,623       48,649       11,652       33,582  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total operating expenses

     33,087       26,932       22,400       108,243       27,612       115,166  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income (loss)

     21,240       7,527       10,254       51,811       11,391       (20,856

Other income (expense)

            

Interest expense, net

     (3,378     (1,202     (661     (6,392     (879     (58,018

Derivatives

     (33,621     (12,275     (12,253     (17,819     (16,622     (8,333

Other

     15       3       805       119       814       (3,184

Reorganization items, net

     —         —         —         —         —         1,144,993  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) before income taxes

     (15,744     (5,947     (1,855     27,719       (5,296     1,054,602  

Income tax benefit

     4,943       —         —         4,943       —         —    
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

     (10,801     (5,947     (1,855     32,662       (5,296     1,054,602  

Preferred stock dividends

     —         —         —         —         —         (5,972
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to common shareholders

   $ (10,801   $ (5,947   $ (1,855   $ 32,662     $ (5,296   $ 1,048,630  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) per share:

 

         

Basic

   $ (0.72   $ (0.40   $ (0.12   $ 2.18     $ (0.35   $ 11.91  

Diluted

   $ (0.72   $ (0.40   $ (0.12   $ 2.17     $ (0.35   $ 8.50  

Weighted average shares outstanding:

 

       

Basic

     15,006       14,994       14,992       14,996       14,992       88,013  

Diluted

 

    

 

15,006

 

 

 

   

 

14,994

 

 

 

   

 

14,992

 

 

 

   

 

15,063

 

 

 

   

 

14,992

 

 

 

   

 

124,087

 

 

 

     Successor     Successor     Successor     Successor     Successor     Predecessor  
     Three Months
Ended
December 31,
    Three Months
Ended
September 30,
    Three Months
Through
December 31,
    Year
Ended
December 31,
    September 13
Through
December 31,
    January 1
Through
September 12,
 
     2017     2017     2016     2017     2016     2016  

Production

            

Crude oil (MBbls)

     845       627       583       2,764       710       2,311  

NGLs (MBbls)

     148       125       137       523       164       533  

Natural gas (MMcf)

     855       676       820       2,949       994       3,012  

Total (MBOE)

     1,135       864       857       3,779       1,040       3,346  

Average daily production (BOEPD)

     12,340       9,396       9,316       10,353       9,449       13,071  

Prices

            

Crude oil ($ per Bbl)

   $ 57.42     $ 47.78     $ 47.41     $ 50.96     $ 46.68     $ 35.21  

NGLs ($ per Bbl)

   $ 22.47     $ 19.19     $ 17.29     $ 19.25     $ 16.53     $ 11.37  

Natural gas ($ per Mcf)

   $ 2.71     $ 2.92     $ 2.82     $ 2.89     $ 2.81     $ 2.06  

Prices - Adjusted for derivative settlements

 

       

Crude oil ($ per Bbl)

   $ 55.24     $ 49.04     $ 48.07     $ 49.69     $ 47.22     $ 55.98  

NGLs ($ per Bbl)

   $ 22.47     $ 19.19     $ 17.29     $ 19.25     $ 16.53     $ 11.37  

Natural gas ($ per Mcf)

   $ 2.71     $ 2.92     $ 2.82     $ 2.89     $ 2.81     $ 2.06  


PENN VIRGINIA CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS - unaudited

(in thousands)

 

     December 31,  
     2017      2016  

Assets

     

Current assets

   $ 87,088      $ 38,884  

Net property and equipment

     529,059        247,473  

Other assets

     13,450        5,329  
  

 

 

    

 

 

 

Total assets

   $ 629,597      $ 291,686  
  

 

 

    

 

 

 

Liabilities and shareholders’ equity

     

Current liabilities

   $ 123,958      $ 62,629  

Other liabilities

     18,733        18,509  

Total long-term debt, net

     265,267        25,000  

Total shareholders’ equity

     221,639        185,548  
  

 

 

    

 

 

 

Total liabilities and shareholders’ equity

   $ 629,597      $ 291,686  
  

 

 

    

 

 

 

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - unaudited

(in thousands)

 

    Successor     Successor     Successor     Successor     Successor     Predecessor  
    Three Months
Ended
December 31,
    Three Months
Ended
September 30,
    Three Months
Ended
December 31,
    Year
Ended
December 31,
    September 13
Through
December 31,
    January 1
Through
September 12,
 
    2017     2017     2016     2017     2016     2016  

Cash flows from operating activities

 

         

Net income (loss)

  $ (10,801   $ (5,947   $ (1,855   $ 32,662     $ (5,296   $ 1,054,602  

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

           

Non-cash reorganization items

    —         —         —         —         —         (1,178,302

Depreciation, depletion and amortization

    17,104       10,659       9,623       48,649       11,652       33,582  

Accretion of firm transportation obligation

    —         —         —         —         —         317  

Derivative contracts:

           

Net losses (gains)

    33,621       12,275       12,253       17,819       16,622       8,333  

Cash settlements, net

    (1,841     788       384       (3,511     384       48,008  

Deferred income tax benefit

    (4,943     —           (4,943     —         —    

(Gain) loss on sales of assets, net

    (24     (9     49       36       49       (1,261

Non-cash exploration expense

    —         —         —         —         —         6,038  

Non-cash interest expense

    760       374       188       2,122       226       22,189  

Share-based compensation (equity-classified)

    1,102       1,013       81       3,809       81       1,511  

Other, net

    2       21       21       61       21       (13

Changes in operating assets and liabilities

    (3,564     (4,897     6,450       (14,994     7,035       35,243  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net cash provided by operating activities

    31,416       14,277       27,194       81,710       30,774       30,247  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cash flows from investing activities

 

         

Acquisitions, net

    (687     (200,162     —         (200,849     —         —    

Capital expenditures

    (47,843     (24,261     (4,812     (115,687     (4,812     (15,359

Proceeds from sales of assets, net

    869       —         —         869       —         224  

Other, net

    —         —         (104     —         (104     1,186  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net cash used in investing activities

    (47,661     (224,423     (4,916     (315,667     (4,916     (13,949
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cash flows from financing activities

 

         

Proceeds from credit facility borrowings

    20,000       25,000       —         59,000       —         75,350  

Repayment of credit facility borrowings

    —         (5,000     (29,350     (7,000     (50,350     (119,121

Proceeds from second lien loans, net

    —         196,000       —         196,000       —         —    

Debt issuance costs paid

    (225     (8,472     —         (9,787     —         (3,011

Proceeds received from rights offering, net

    —         —         —         55       —         49,943  

Other, net

    —         —         (161     (55     (161     —    
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net cash provided by (used in) financing activities

    19,775       207,528       (29,511     238,213       (50,511     3,161  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net increase (decrease) in cash and cash equivalents

    3,530       (2,618     (7,233     4,256       (24,653     19,459  

Cash and cash equivalents - beginning of period

    7,487       10,105       13,994       6,761       31,414       11,955  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cash and cash equivalents - end of period

  $ 11,017     $ 7,487     $ 6,761     $ 11,017     $ 6,761     $ 31,414  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 


PENN VIRGINIA CORPORATION

CERTAIN NON-GAAP FINANCIAL MEASURES - unaudited

(in thousands, except per unit amounts)

Readers are reminded that non-GAAP measures are merely a supplement to, and not a replacement for, or superior to financial measures prepared according to GAAP. They should be evaluated in conjunction with the GAAP financial measures. It should be noted as well that the Company’s non-GAAP information may be different from the non-GAAP information provided by other companies.

Table 1

Reconciliation of GAAP “Net income (loss)” to Non-GAAP “Adjusted net income (loss) attributable to common shareholders”

Adjusted net income (loss) is a non-GAAP financial measure that represents net income (loss) adjusted to exclude the effects, net of income taxes, of non-cash changes in the fair value of derivatives, net gains and losses on the sales of assets, acquisition transaction costs, reorganization items, strategic and financial advisory costs, restructuring expenses and account write-offs and reserves prior to our emergence from bankruptcy. We believe that Non-GAAP adjusted net income (loss) and non-GAAP adjusted net income (loss) per share amounts provide meaningful supplemental information regarding our operational performance. This information facilitates management’s internal comparisons to the Company’s historical operating results as well as to the operating results of our competitors. Since management finds this measure to be useful, the Company believes that our investors can benefit by evaluating both non-GAAP and GAAP results. Adjusted net income (loss) non-GAAP 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 (loss).

 

     Successor     Successor     Successor     Successor     Successor     Predecessor  
     Three Months
Ended
December 31,
    Three Months
Ended
September 30,
    Three Months
Through
December 31,
    Year
Ended
December 31,
    September 13
Through
December 31,
    January 1
Through
September 12,
 
     2017     2017     2016     2017     2016     2016  

Net income (loss)

   $ (10,801   $ (5,947   $ (1,855   $ 32,662     $ (5,296   $ 1,054,602  

Adjustments for derivatives:

            

Net losses (gains)

     33,621       12,275       12,253       17,819       16,622       8,333  

Cash settlements, net

     (1,841     788       384       (3,511     384       48,008  

(Gain) loss on sale of assets, net

     (24     (9     49       36       49       (1,261

Acquisition transaction costs

     (165     1,505       —         1,340       —         —    

Reorganization items, net

     —         —         —         —         —         (1,144,993

Strategic and financial advisory costs

     —         —         —         —         —         18,036  

Restructuring expenses

     —         —         (116     (20     (98     3,821  

Account write-offs and reserves prior to emergence from bankruptcy

     —         —         —         —         —         3,123  

Impact of adjustment on income taxes

     (4,943     —         —         (4,943     —         —    
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted net income (loss)

   $ 15,847     $ 8,612     $ 10,715     $ 43,383     $ 11,661     $ (10,331
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted net income (loss) attributable to common shareholders, per diluted share

   $ 1.06     $ 0.57     $ 0.71     $ 2.88     $ 0.78     $ (0.08
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 


Table 2

Reconciliation of GAAP “Net income (loss)” to Non-GAAP “Adjusted EBITDAX”

Adjusted EBITDAX represents net income (loss) before interest expense, income tax expense (benefit), depreciation, depletion and amortization expense, exploration, and share-based compensation expense, further adjusted to exclude the effects of gains and losses on sales of assets, accretion of firm transportation obligation, non-cash changes in the fair value of derivatives, and special items including acquisition transaction costs, reorganization items, strategic and financial advisory costs, restructuring expenses and account write-offs and reserves prior to our emergence from bankruptcy. We believe this presentation is commonly used by investors and professional research analysts for 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 income (loss). Adjusted EBITDAX as defined by Penn Virginia may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net income (loss) and other measures prepared in accordance with GAAP, such as operating income or cash flows from operating activities. Adjusted EBITDAX should not be considered in isolation or as a substitute for an analysis of Penn Virginia’s results as reported under GAAP.

 

     Successor     Successor     Successor     Successor     Successor     Predecessor  
     Three Months
Ended
December 31,
    Three Months
Ended
September 30,
    Three Months
Through
December 31,
    Year
Ended
December 31,
    September 13
Through
December 31,
    January 1
Through
September 12,
 
     2017     2017     2016     2017     2016     2016  

Net income (loss)

   $ (10,801   $ (5,947   $ (1,855   $ 32,662     $ (5,296   $ 1,054,602  

Adjustments to reconcile to Adjusted EBITDAX:

 

       

Interest expense, net

     3,378       1,202       661       6,392       879       58,018  

Income tax benefit

     (4,943     —         —         (4,943     —         —    

Depreciation, depletion and amortization

     17,104       10,659       9,623       48,649       11,652       33,582  

Exploration

     —         —         —         —         —         10,288  

Share-based compensation expense (equity-classified)

     1,102       1,013       81       3,809       81       1,511  

(Gain) loss on sale of assets, net

     (24     (9     49       36       49       (1,261

Accretion of firm transportation obligation

     —         —         —         —         —         317  

Adjustments for derivatives:

            

Net losses (gains)

     33,621       12,275       12,253       17,819       16,622       8,333  

Cash settlements, net

     (1,841     788       384       (3,511     384       48,008  

Adjustment for special items:

            

Acquisition transaction costs

     (165     1,505       —         1,340       —         —    

Reorganization items, net

     —         —         —         —         —         (1,144,993

Strategic and financial advisory costs

     —         —         —         —         —         18,036  

Restructuring expenses

     —         —         (116     (20     (98     3,821  

Account write-offs and reserves prior to emergence from bankruptcy

     —         —         —         —         —         3,123  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDAX

   $ 37,431     $ 21,486     $ 21,080     $ 102,233     $ 24,273     $ 93,385  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDAX per BOE

   $ 32.97     $ 24.85     $ 24.60     $ 27.05     $ 23.35     $ 27.91  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 


Table 3

Reconciliation of GAAP “Standardized Measure of Discounted Future Net Cash Flows” to Non-GAAP “PV-10”

Non-GAAP PV-10 value is the estimated future net cash flows from estimated proved reserves discounted at an annual rate of 10 percent before giving effect to income taxes. The standardized measure of discounted future net cash flows is the after-tax estimated future cash flows from estimated proved reserves discounted at an annual rate of 10 percent, determined in accordance with generally accepted accounting principles (GAAP). We use non-GAAP PV-10 value as one measure of the value of our estimated proved reserves and to compare relative values of proved reserves among exploration and production companies without regard to income taxes. We believe that securities analysts and rating agencies use PV-10 value in similar ways. Our management believes PV-10 value is a useful measure for comparison of proved reserve values among companies because, unlike standardized measure, it excludes future income taxes that often depend principally on the characteristics of the owner of the reserves rather than on the nature, location and quality of the reserves themselves.

 

     December 31,  
(in thousands)    2017      2016 (1)  

Standardized measure of future discounted cash flows

   $ 590,484      $ 317,550  

Present value of future income taxes discounted at 10%

     18,486        —    
  

 

 

    

 

 

 

PV-10

   $ 608,970      $ 317,550  
  

 

 

    

 

 

 
  

 

 

    

 

 

 

 

(1)  Due primarily to our net operating loss carry forwards, our standardized measure of future discounted cash flows does not include any income tax effect.

Table 4

 

     NYMEX PRICING USED IN THE
CALCULATION OF PV-10 AT STRIP
 
     Calendar Year Average  
     Oil
(per barrel)
     Natural Gas
(per MMBtu)
 

2018

   $ 59.55      $ 2.87  

2019

   $ 56.22      $ 2.81  

2020

   $ 53.79      $ 2.82  

2021

   $ 52.29      $ 2.85  

2022

   $ 51.70      $ 2.89  

2023

   $ 51.59      $ 2.93  

2024

   $ 51.76      $ 2.97  

2025

   $ 52.07      $ 3.01  

2026

   $ 52.47      $ 3.07  

The Company used the average pricing for the year shown above and flat pricing after 2026.


Table 5

Reconciliation of GAAP “General administrative expenses” to Non-GAAP “Adjusted cash-based general and administrative expenses”

Adjusted cash-based general and administrative expense (“Adjusted G&A”) is a supplemental non-GAAP financial measure that excludes certain non-recurring expenses and non-cash share-based compensation expense. We believe that the non-GAAP measure of Adjusted G&A is useful to investors because it provides readers with a meaningful measure of our recurring G&A expense and provides for greater comparability period-over-period. The table details all adjustments to G&A on a GAAP basis to arrive at Adjusted G&A.

 

     Successor     Successor     Successor     Successor     Successor     Predecessor  
     Three Months
Ended
December 31,
    Three Months
Ended
September 30,
    Three Months
Through
December 31,
    Year
Ended
December 31,
    September 13
Through
December 31,
    January 1
Through
September 12,
 
     2017     2017     2016     2017     2016     2016  

General and administrative expenses - direct

   $ 2,360     $ 5,939     $ 3,531     $ 14,453     $ 5,007     $ 37,434  

Share-based compensation - equity-classified awards

     1,102       1,013       81       3,809       81       1,511  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

GAAP General and administrative expenses

     3,462       6,952       3,612       18,262       5,088       38,945  

Less: Share-based compensation - equity-classified awards

     (1,102     (1,013     (81     (3,809     (81     (1,511

Significant special charges:

            

Acquisition transaction costs

     165       (1,505     —         (1,340     —         —    

Strategic and financial advisory costs

     —         —         —         —         —         (18,036

Restructuring expenses

     —         —         116       20       98       (3,821
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted cash-based general and administrative expenses

   $ 2,525     $ 4,434     $ 3,647     $ 13,133     $ 5,105     $ 15,577  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted cash-based general and administrative expenses per BOE

   $ 2.22     $ 5.13     $ 4.26     $ 3.48     $ 4.91     $ 4.66  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 


Definitions and Calculations

Drill-Bit Finding and Development Cost - Definition

Drill-bit finding and development costs for full year 2017 of approximately $4.40 per BOE was calculated by dividing the sum of exploration costs and development costs of $133.0 million by total reserve, extensions and discoveries of 30.2 MMBOE. Drill-bit finding and development cost is a supplemental measure used to assist in an evaluation of how much it costs the Company, on a per BOE basis, to add proved reserves. This calculation does not include the future development costs required for the development of proved undeveloped reserves.

Reserve Replacement Ratio - Definition

The Company uses the reserves replacement ratio as an indicator of the Company’s ability to replenish annual production volumes and grow its reserves, thereby providing some information on the sources of future production. The reserves replacement ratio is a statistical indicator that is limited because it typically varies widely based on the extent and timing of discoveries and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not embed the cost or timing of future production of new reserves, it cannot be used as a measure of value creation. The reserve replacement ratio of approximately 710% was calculated by dividing net proved reserve additions of 26.9 MMBOE (the sum of extensions, discoveries, revisions and purchases) by production of 3.8 MMBOE.