Exhibit 99.1
Rex Energy Reports Fourth Quarter and Full Year 2012 Operational and Financial Results
| • | | Reached 100,000 net acres in Appalachian Basin |
| • | | Second Upper Devonian Burkett well, Drushel 6-HD, produced into sales at a 5-day rate of 7.3 MMcfe/d (assuming full ethane recovery) |
| • | | Reached peak daily rate of 849 gross BOPD from Illinois conventional drilling program; exceeded goal of 400 gross BOPD |
| • | | Achieved 2012 liquids exit rate of 30%; grew fourth quarter 2012 liquids production by 43% over fourth quarter 2011 |
| • | | Recently completed Meyer 2H produced into sales at a 5-day rate of 6.9 MMcfe/d (assuming full ethane recovery) |
| • | | Entered into ethane sales agreement with NOVA Chemicals Corporation on Mariner West pipeline |
| • | | Increased proved reserves at December 31, 2012 by 69% over December 31, 2011; Drill-bit F&D of $0.90 per Mcfe for 2012 |
STATE COLLEGE, PA., February 26, 2012 (GLOBE NEWSWIRE) – Rex Energy Corporation (Nasdaq: REXX) today announced its fourth quarter 2012 and full year 2012 operational and financial results.
Fourth Quarter Financial Results
Operating revenues from continuing operations for the three months ended December 31, 2012 were $45.1 million, which represents an increase of 42% over the same period in 2011. Commodity revenues, including cash-settled derivatives, were $43.5 million, an increase of 31% over the comparable period of 2011. Commodity revenues and cash-settled derivatives from oil and natural gas liquids (NGLs) represented 55% of total commodity revenues (including cash-settled derivatives) for the three months ended December 31, 2012.
Lease operating expense (LOE) from continuing operations was $13.1 million, or $1.93 per Mcfe for the quarter, a 4% decrease on a per unit basis compared to the same period in 2011. Cash general and administrative (G&A) expenses from continuing operations were $4.3 million for the three months ended December 31, 2012, which represents a 40% decrease on a per unit basis as compared to the same period in 2011.
As a result of the continued low natural gas price environment, Rex Energy incurred a non-cash impairment charge of approximately $17.2 million in the fourth quarter of 2012 related to certain developed dry natural gas properties and non-core unevaluated leases which are not expected to be developed prior to their expiration.
Loss from continuing operations attributable to Rex Energy common shareholders for the three months ended December 31, 2012 was $1.3 million, or $0.03 per share. Adjusted net income, a non-GAAP measure, for the three months ended December 31, 2012 was $6.0 million, or $0.11 per share. A reconciliation of adjusted net income to GAAP net income for fourth quarter and full year 2012, as well as a discussion of the uses of the measure, is presented in the appendix attached to this release.
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EBITDAX from continuing operations, a non-GAAP measure, was $26.4 million for the fourth quarter, an increase of 33% over the fourth quarter of 2011 and 16% over the third quarter of 2012. A reconciliation of EBITDAX to GAAP net income for fourth quarter and full year 2012, as well as a discussion of the uses of the measure, is presented in the appendix attached to this release.
Full Year 2012 Financial Results
Operating revenues from continuing operations for the full year 2012 were $148.1 million, which is an increase of 29% over full year 2011 operating revenues. Commodity revenues, including cash-settled derivatives, were $150.8 million, an increase of 28% over full year 2011. Commodity revenues and cash-settled derivatives from oil and natural gas liquids (NGLs) represented 54% of total commodity revenues (including cash settled derivatives) for the twelve months ended December 31, 2012.
For the full year 2012, LOE from continuing operations was $47.6 million, or $1.94 per Mcfe, a 17% decrease on per unit basis compared to full year 2011. Cash G&A expenses from continuing operations were $20.2 million for full year 2012, which represents a 47% decrease on a per unit basis as compared to full year 2011.
Income from continuing operations attributable to Rex Energy common shareholders for full year 2012 was $56.4 million, or $1.09 per share. Adjusted net income for full year 2012 was $16.7 million, or $0.32 per share. EBITDAX from continuing operations was $88.7 million for full year 2012, an increase of 36% over full year 2011.
Production Update
Fourth quarter 2012 net production volumes were 73.9 MMcfe/d, consisting of 52.5 MMcfe/d of natural gas and 3.6 Mboe/d of oil and NGLs, an increase in liquids production of 43% over the fourth quarter of 2011 and 18% over the third quarter of 2012. Oil and NGLs accounted for 29% of total net production during the fourth quarter of 2012 and accounted for 30% of the December 2012 net production exit rate. For full year 2012, net production volumes were 67.1 MMcfe/d, consisting of 49.2 MMcfe/d of natural gas and 3.0 Mboe/d of oil and NGLs, an increase in total production of 73% over full year 2011. Oil and NGLs accounted for 27% of total net production during the year.
Including the effect of cash-settled derivatives, realized prices for the three months ended December 31, 2012 were $4.10 per Mcf for natural gas, $85.33 per barrel for oil and condensate and $49.60 per barrel for NGLs, which was approximately 56% of the average quoted NYMEX oil price for the fourth quarter. Realized prices before the effects of hedging were $3.54 per Mcf for natural gas, $85.33 per barrel for oil and condensate and $48.27 per barrel for NGLs, which was approximately 55% of the average quoted NYMEX oil price for the fourth quarter.
Realized prices, including the effect of cash-settled derivatives, for the twelve months ended December 31, 2012 were $3.83 per Mcf for natural gas, $90.22 for oil and condensate and $43.75 per barrel for NGLs. Realized prices before the effects of hedging were $2.94 per Mcf for natural gas, $90.61 per barrel of oil and condensate and $42.60 per barrel for NGLs.
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Full Year 2012 Capital Investments
For full year 2012, the company made operational capital investments of approximately $187.9 million, of which $148.9 million was used to fund Marcellus and Utica operations, $34.8 million was used to fund conventional drilling, water flood enhancement and ASP projects in the Illinois Basin, and $4.2 million was capitalized interest and corporate expenditures. The Marcellus and Utica capital investment funded the drilling of 31 gross (21.0 net) wells, fracture stimulation of 26 gross (17.0 net) wells, placing 24 gross (15.7 net) wells into service and other projects related to drilling and completing wells in the Marcellus region.
Total capital investments for leasing were $51.0 million for the full year 2012. Further details are provided below in the land update.
Operational Update
Note: Unless specifically stated otherwise in this operational update, all numbers are gross.
Appalachian Basin – Butler Operated Area, Pennsylvania
In the Butler Operated Area, the company drilled 21 gross (14.7 net) wells in 2012, with 20 gross (12.9 net) wells fracture stimulated and 22 gross (14.3 net) wells placed into service. The company had 18 gross (12.6 net) wells drilled and awaiting completion as of December 31, 2012.
During the quarter, the company completed and placed into service the two-well Voll pad. The two wells were completed using a 225’ stage frac design. In addition, the company completed the Meyer 2H in the first quarter of 2013 with a lateral length of 4,028’, utilizing its 150’ stage “Super Frac” design with a 27-stage fracture stimulation. Lastly, the company has completed its second Upper Devonian Burkett well in the first quarter of 2013, the Drushel 6-HD. The well was completed with a lateral length of 4,036’ utilizing the company’s 150’ stage “Super Frac” design with a 27 stage fracture stimulation.
The table below lists, where available, the 5-day and 30-day sales rates for the company’s recent completions.
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5-Day Sales Rate (Average Per Well)1 | |
Well Name | | Target Formation | | Natural Gas
(Mcf/d) | | | Condensate
(Bbls/d) | | | NGLs
(Bbls/d) | | | Total
(Mcfe/d) | | | % Liquids | | | Total – Ethane
Rejection
(Mcfe/d) | |
Plesniak 3H, 9H | | Marcellus | | | 2,288 | | | | 3 | | | | 436 | | | | 4,922 | | | | 54 | % | | | 3,496 | |
Pallack 1H, 3H | | Marcellus | | | 2,016 | | | | 4 | | | | 391 | | | | 4,385 | | | | 54 | % | | | 3,070 | |
Voll 3H, 4H | | Marcellus | | | 2,699 | | | | 0 | | | | 415 | | | | 5,189 | | | | 48 | % | | | 3,810 | |
Meyer 2H | | Marcellus | | | 3,544 | | | | 2 | | | | 562 | | | | 6,929 | | | | 49 | % | | | 4,922 | |
Drushel 6HD2 | | Upper Devonian | | | 3,748 | | | | 12 | | | | 580 | | | | 7,302 | | | | 49 | % | | | 5,206 | |
| 1 | Placed into sales using various shut-in periods and choke sizes |
| 2 | Last 5 days have averaged 25 bbls/d of condensate |
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| | | | | | | | | | | | | | | | | | | | | | | | | | |
30-Day Sales Rate (Average Per Well)1 | |
Well Name | | Target Formation | | Natural Gas
(Mcf/d) | | | Condensate
(Bbls/d) | | | NGLs
(Bbls/d) | | | Total
(Mcfe/d) | | | % Liquids | | | Total – Ethane
Rejection
(Mcfe/d) | |
Plesniak 3H, 9H | | Marcellus | | | 2,154 | | | | 4 | | | | 412 | | | | 4,650 | | | | 54 | % | | | 3,301 | |
Pallack 1H, 3H | | Marcellus | | | 1,740 | | | | 3 | | | | 337 | | | | 3,782 | | | | 54 | % | | | 2,647 | |
Voll 3H, 4H | | Marcellus | | | 2,511 | | | | 0 | | | | 385 | | | | 4,822 | | | | 48 | % | | | 3,538 | |
| 1 | Placed into sales using various shut-in periods and choke sizes |
The company drilled its third and fourth Upper Devonian Burkett wells during the fourth quarter of 2012. Of the four Upper Devonian Burkett wells drilled to date, one of these wells, the Burgh 2HD, lies within the company’s Super Rich Marcellus area. The company intends to drill one additional Upper Devonian Burkett well in 2013 and complete the remaining three wells (the Drushel 6-HD has already been completed) during 2013. By the end of 2013, the company expects to have five Upper Devonian Burkett wells flowing into sales.
As previously announced, the company drilled two Super Rich Marcellus wells in 2012, the Wack 9H well and the Grubbs 2H well, and plans to place these wells into sales in the second quarter of 2013. These wells are intended to further delineate the company’s increased liquids potential in the northwest portion of its Butler Operated Area.
| | | | | | | | |
| Total Operated Area – Butler County, PA |
| | | Wells Drilled | | Wells Fracture Stimulated | | Wells Placed Into Service | | Wells Awaiting Completion |
YTD 2013 | | 2 | | 6 | | 2 | | 13 |
FY 2013 Forecast | | 19 | | 22 | | 21 | | 15 |
Rex Energy is also pleased to announce that it has entered into a 15-year sales agreement with NOVA Chemicals Corporation (NOVA Chemicals) to sell ethane produced in the company’s Butler Operated Area via the Mariner West pipeline project. Ethane produced in Rex Energy’s Butler Operated Area will be transported from MarkWest Energy Partners’ (MWE) Sarsen and Bluestone cryogenic processing facilities via MWE’s planned Y-Grade line to the Houston Fractionation Complex. Volumes to be sold under the agreement are set at 2,000 barrels per day of ethane and, pending the exercise of an option by NOVA Chemicals, could increase over the term of the agreement.
Appalachian Basin – Warrior North Prospect, Carroll County, Ohio
In the Warrior North Prospect, the company drilled 2 gross (2.0 net) wells in 2012, with 1 gross (1.0 net) well fracture stimulated and 1 gross (1.0 net) well placed into service. The company had 1 gross (1.0 net) well drilled and awaiting completion as of December 31, 2012.
As previously announced, Rex Energy placed into sales its first Ohio Utica well, the Brace 1H, located in Carroll County, Ohio, at a 24-hour sales rate (assuming full ethane recovery) of 1,094 Boe/d (43% NGLs, 31% gas, 26% condensate). The well went on to average a 30-day sales rate (assuming full ethane recovery) of 731 Boe/d, a 60-day sales rate (assuming full ethane recovery) of 597 Boe/d and a 90-day sales rate of 515 Boe/d (assuming full ethane recovery).
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The company drilled two wells on the G. Graham pad in its Warrior North prospect and is currently drilling the first of two wells on the Brace West pad. The G. Graham wells are currently being completed and will be shut-in for approximately 60 days prior to being placed in service in the second quarter of 2013.
Appalachian Basin – Warrior South Prospect, Guernsey, Noble & Belmont Counties, Ohio
The company drilled and completed its first three planned wells in the Warrior South Prospect in the fourth quarter of 2012. The wells have been shut-in since completion and will be placed into sales once the related infrastructure is in place, which is currently expected to be in June 2013.
| | | | | | | | |
| Total Operated Area – Ohio Utica Shale |
| | | Wells Drilled | | Wells Fracture Stimulated | | Wells Placed Into Service | | Wells Awaiting Completion |
YTD 2013 | | 1 | | 1 | | 0 | | 1 |
FY 2013 Forecast | | 11 | | 9 | | 11 | | 3 |
Appalachian Basin – Westmoreland, Clearfield and Centre Counties, Pennsylvania
In the company’s non-operated Westmoreland, Clearfield and Centre counties, Pennsylvania, where WPX Energy serves as the operator, the combined average production for a recent 5-day period was 54.8 MMcf/d. For the month of December, the average production rate in the combined non-operated regions was approximately 57.6 MMcfe/d.
| | | | | | | | |
| Total Non-Operated Area – Westmoreland, Clearfield and Centre Counties, PA |
| | | Wells Drilled | | Wells Fracture Stimulated | | Wells Placed Into Service | | Wells Awaiting Completion |
YTD 2013 | | 0 | | 0 | | 0 | | 0 |
FY 2013 Forecast | | 0 | | 7 | | 7 | | 0 |
Illinois Basin – Conventional
In the Illinois Basin, the company is continuing its previously announced conventional drilling and re-completion program to increase its oil production. In 2012, the company drilled and completed 8 wells and performed re-completion operations on an additional 15 wells. The 23 wells that were completed since June 2012 produced at a peak daily rate of 849 gross BOPD, exceeding the previously announced estimate of 400 gross BOPD of incremental oil production.
In 2013, the company plans to spend approximately $18 million to drill and re-complete 28 wells to further delineate its acreage and test multiple zones in the Illinois Basin. While the company will continue to vertically test its acreage in the Illinois Basin, the company has begun drilling its first horizontal test well in the region.
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Illinois Basin – ASP Project Update
In the Perkins-Smith expansion project, the company is at the end of the ASP injection period which was initiated in June 2012. The polymer drive stage of the project is expected to commence by the second quarter of 2013. Initial production response is still expected in mid-year 2013, with peak production response from the Perkins-Smith unit expected at the end of 2013. In the Delta Unit, all drilling and infrastructure for the project has been completed. Full field pre-flush injection is scheduled to commence during the first quarter of 2013 with ASP injection scheduled for the fourth quarter of 2013. The company successfully booked approximately 758 net MBO of proved reserves at December 31, 2012 for the Delta Unit.
Land Update
During 2012, the company added approximately 3,600 net acres in its Butler Operated Area, increasing its total leasehold in the region to approximately 48,400 net acres. With its approximately 20,000 net acres in the Warrior Prospects, joint venture acreage with WPX Energy, and other Utica acreage in Pennsylvania, Rex Energy has exceeded 100,000 net acres in the Appalachian Basin, an important milestone in the company’s history. Of the over 100,000 net acres, approximately 75% is liquids rich and approximately 20% is part of the company’s joint venture with WPX Energy. Additionally, the company has no significant liquids rich acreage subject to near term expiration.
Estimated Proved Reserves
Rex Energy reported proved oil and natural gas reserves as of December 31, 2012 of 618.1 Bcfe, an increase of 69% over December 31, 2011. Of the 618.1 Bcfe of proved reserves, 40% was attributable to oil, natural gas liquids and condensate, assuming full ethane recoveries. Excluding ethane recoveries, proved reserves increased to 496.5 Bcfe, which is an increase of 36% over proved reserves as of December 31, 2011. The proved developed portion of the reserves increased to 257.9 Bcfe from 173.3 Bcfe as of December 31, 2011. The proved reserves estimates as of December 31, 2012 were prepared by the company’s independent third-party reserve engineers, Netherland, Sewell & Associates, Inc. Rex Energy successfully replaced 802% of its estimated production of 24,557 MMcfe for the twelve months ended December 31, 2012 with a proved reserves-to-production ratio of 25.2 years. For more information on proved reserves and related information, see “Note on Hydrocarbon Volumes and Estimates” below.
The following table summarizes the company’s proved reserves and Finding and Development Costs as of December 31, 2010, 2011, and 2012.
| | | | | | | | | | | | | | | | |
| | | 12/31/2010 | | | 12/31/2011 | | | 12/31/2012 | | | Average | |
Proved Reserves (MMcfe)1 | | | 201,679 | | | | 366,188 | | | | 618,050 | | | | — | |
Production (MMcfe) | | | 7,391 | | | | 14,220 | | | | 24,557 | | | | — | |
Drill-Bit Capital Deployed (millions)2, 3 | | $ | 76.3 | | | $ | 192.8 | | | $ | 176.9 | | | | — | |
Drill-Bit Finding and Development Cost ($/Mcfe) 2 | | $ | 0.67 | | | $ | 1.24 | | | $ | 0.90 | | | $ | 0.96 | |
All-In Capital Deployed (millions)2, 4 | | $ | 164.5 | | | $ | 302.4 | | | $ | 238.9 | | | | — | |
All-In Finding and Development Cost ($/Mcfe) 2 | | $ | 2.15 | | | $ | 1.84 | | | $ | 0.95 | | | $ | 1.43 | |
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| 1 | Values obtained from certified report from Netherland, Sewell & Associates, Inc. as of December 31, 2010, December 31, 2011 and December 31, 2012, respectively |
| 2 | A non-GAAP measure. A further discussion of Finding and Development Cost and components thereof is included in the appendix attached to this release |
| 3 | Exploration and development capital employed. Estimates of exploration and development costs for year ended December 31, 2012 were $176.9 million |
| 4 | Includes all exploration and development capital, leasing and other corporate capital spending |
Finding and Development Cost per unit of production is a non-GAAP metric used by the industry, investors and analysts to measure the company’s ability to establish a long-term trend of adding reserves at a reasonable cost. A further discussion of Finding and Development Cost per unit of production is included in the appendix attached to this release.
Below is a reconciliation of the changes in the company’s proved reserves between December 31, 2011 and December 31, 2012 (SEC pricing for the twelve months ended December 31, 2012 was the West Texas Intermediate posted price of $91.21/Bbl for oil and NGLs and Henry Hub spot price of $2.76/Mcf for natural gas, adjusted for contractual agreements).
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| | | Natural Gas
(MMcf) | | | Oil
(Mbbl) | | | C3+ NGLs
(Mbbl) | | | Ethane
(Mbbl) | | | Total
(MMcfe) | |
Balance – December 31, 2011 | | | 274,292 | | | | 8,181 | | | | 7,135 | | | | 0 | | | | 366,188 | |
Extensions and discoveries | | | 116,854 | | | | 475 | | | | 4,640 | | | | 8,173 | | | | 196,582 | |
Production1 | | | (18,017 | ) | | | (732 | ) | | | (358 | ) | | | 0 | | | | (24,557 | ) |
Acquisition & divestitures | | | 0 | | | | 43 | | | | 0 | | | | 0 | | | | 259 | |
Revisions to previous estimates2 | | | (1,413 | ) | | | 1,409 | | | | 5 | | | | 12,085 | | | | 79,578 | |
| | | | | | | | | | | | | | | | | | | | |
Balance – December 31, 20123 | | | 371,716 | | | | 9,376 | | | | 11,422 | | | | 20,258 | | | | 618,050 | |
| | | | | | | | | | | | | | | | | | | | |
Proved Developed Reserves as of December 31, 20124 | | | 141,755 | | | | 9,216 | | | | 3,845 | | | | 6,299 | | | | 257,915 | |
| 1 | Unaudited 2012 production figures for the twelve months ended December 31, 2012 |
| 2 | Includes improved recovery of 758 Mbbl from Delta ASP project |
| 3 | Total proved reserves increased 69% as compared to December 31, 2011 |
| 4 | Proved developed reserves as of December 31, 2012 in Butler Operated Area include 38 Bcfe related to ethane |
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The following table summarizes Rex Energy’s total proved reserves by region as of December 31, 2012:
| | | | | | | | | | | | | | | | | | | | |
| | | Proved Reserves by Asset Area | |
| | | PDP
(MMcfe) | | | PDNP
(MMcfe) | | | PUD
(MMcfe) | | | Total
(MMcfe) | | | PV10
(M$) | |
Appalachia Basin | | | | | | | | | | | | | | | | | | | | |
Butler Operated Area and Warrior Prospects | | | 144,504 | | | | 1,086 | | | | 292,757 | | | | 438,347 | | | | 238,204 | |
Westmoreland, Centre, Clearfield Counties – Non-Operated | | | 52,018 | | | | 2,360 | | | | 67,163 | | | | 121,541 | | | | 37,721 | |
All Other Appalachia | | | 3,248 | | | | — | | | | — | | | | 3,248 | | | | 2,428 | |
Illinois Basin | | | 49,686 | | | | 5,012 | | | | 216 | | | | 54,914 | | | | 222,179 | |
| | | | | | | | | | | | | | | | | | | | |
Total | | | 249,456 | | | | 8,458 | | | | 360,136 | | | | 618,050 | | | | 500,532 | |
| | | | | | | | | | | | | | | | | | | | |
| 1 | PV-10 is a non-GAAP financial measure because it excludes the effect of income taxes and asset retirement obligations. A further discussion of PV-10 as well as a reconciliation to the most directly comparable GAAP measure is included in the appendix attached to this release. |
Below is a summary of the number of net wells by proved reserve classification for the company’s Appalachian Basin as of December 31, 2010, 2011, and 2012.
| | | | | | | | | | | | |
Total Company Net Appalachia Basin Wells1 | |
| | | 12/31/2010 | | | 12/31/2011 | | | 12/31/2012 | |
PDP | | | 12.8 | | | | 37.1 | | | | 53.6 | |
PDNP | | | 2.8 | | | | 2.1 | | | | 0.4 | |
PUD | | | 35.8 | | | | 49.8 | | | | 58.1 | |
| | | | | | | | | | | | |
Total | | | 51.4 | | | | 89.0 | | | | 112.1 | |
| | | | | | | | | | | | |
PUD:PD Ratio | | | 2.29 | | | | 1.27 | | | | 1.08 | |
| 1 | Includes Marcellus, Utica, and Upper Devonian wells only |
The proved undeveloped to proved developed ratio for the period ending December 31, 2012 is 1.08 to 1.
Liquidity Update
During the fourth quarter of 2012, Rex Energy completed an offering of $250 million in aggregate principal amount of senior notes due 2020 in a private placement. The company used the net proceeds of approximately $243 million to repay all of the borrowings under its revolving credit facility and to repay in full, its second lien term loan. The company’s $240 million borrowing base on its revolving credit facility, which was completely undrawn at the end of the year, is scheduled for its next redetermination in March 2013. The company had approximately $284 million in liquidity entering 2013.
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First Quarter and Full Year 2013 Guidance
Rex Energy is providing its initial guidance for the first quarter and maintaining its full year 2013 guidance ($ in millions):
| | | | |
| | | 1Q2013 | | Full Year 2013 |
Production | | 71.5 – 73.5 MMcfe/d | | 90.5 – 94.5 MMcfe/d |
Lease Operating Expense | | $13.0 – $14.5 | | $58 – $62 |
Cash G&A | | $5.8 – $6.8 | | $26 – $29 |
Capital Expenditures* | | — | | $230 – $250 |
| * | Land acquisition expense is not included in the capital expenditures budget |
Conference Call Information
Management will host a live conference call and webcast on Wednesday, February 27, 2013 at 10:00 a.m. ET to review fourth quarter and full year financial results and operational highlights. All financial results included in this release or discussed on the conference call will remain subject to our independent auditor’s review. The telephone number to access the conference call is (877) 654-5175. Presentation slides containing reference materials for the call and webcast will be available on the company’s website,www.rexenergy.com, under the Investor Relations tab. The replay of the event and reference materials will be available on the company’s website through March 28, 2013.
About Rex Energy Corporation
Rex Energy is headquartered in State College, Pennsylvania and is an independent oil and gas exploration and production company operating in the Appalachian and Illinois Basins within the United States. The company’s strategy is to pursue its higher potential exploration drilling prospects while acquiring oil and natural gas properties complementary to its portfolio.
Forward-Looking Statements
Except for historical information, statements made in this release, including those relating to the timing and nature of Marcellus and Utica Shale development plans; drilling and completion schedules; anticipated fracture stimulation activities; availability of midstream infrastructure; the ASP pilot and conventional expansion plans in the Illinois Basin; and the company’s financial guidance and projections for 2013 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. Forward-looking statements may contain words such as “expected”, “expects”, “scheduled”, “planned”, “plans”, “anticipates” and similar words. These statements are based on management’s experience and perception of historical trends, current conditions, and anticipated future developments, as well as other factors believed to be appropriate. We believe these statements and the assumptions and estimates contained in this release are reasonable based on information that is currently available to us. However, management’s assumptions and the company’s future performance are subject to a wide range of business risks and uncertainties, both known and unknown, and we cannot assure that the company can or will meet the goals, expectations, and projections included in this release. Any number of factors could cause our actual results to be materially different from those expressed or implied in our forward looking statements, including (without limitation):
| | • | | economic conditions in the United States and globally; |
| | • | | domestic and global demand for oil, NGLs and natural gas; |
| | • | | volatility in oil, NGL, and natural gas pricing; |
| | • | | new or changing government regulations, including those relating to environmental matters, permitting, or other aspects of our operations; |
| | • | | the geologic quality of the company’s properties with regard to, among other things, the existence of hydrocarbons in economic quantities; |
| | • | | uncertainties inherent in the estimates of our oil and natural gas reserves; |
| | • | | our ability to increase oil and natural gas production and income through exploration and development; |
| | • | | drilling and operating risks; |
| | • | | the success of our drilling techniques in both conventional and unconventional reservoirs; |
| | • | | the success of the secondary and tertiary recovery methods we utilize or plan to employ in the future; |
| | • | | the number of potential well locations to be drilled, the cost to drill them, and the time frame within which they will be drilled; |
| | • | | the ability of contractors to timely and adequately perform their drilling, construction, well stimulation, completion and production services; |
| | • | | the availability of equipment, such as drilling rigs, and infrastructure, such as transportation, pipelines, processing and midstream services; |
| | • | | the effects of adverse weather or other natural disasters on our operations; |
| | • | | competition in the oil and gas industry in general, and specifically in our areas of operations; |
| | • | | changes in our drilling plans and related budgets; |
| | • | | the success of prospect development and property acquisition; |
| | • | | the success of our business and financial strategies, and hedging strategies; |
| | • | | conditions in the domestic and global capital and credit markets and their effect on us; |
| | • | | the adequacy and availability of capital resources, credit, and liquidity including, but not limited to, access to additional borrowing capacity; and |
| | • | | uncertainties related to the legal and regulatory environment for our industry, and our own legal proceedings and their outcome. |
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The company undertakes no obligation to publicly update or revise any forward-looking statements. Further information on the company’s risks and uncertainties is available in the company’s filings with the Securities and Exchange Commission.
Note on Hydrocarbon Volumes and Estimates
The estimates of proved reserves in this release are based on a reserve report of our independent external reserve engineers as of December 31, 2012. “Proved reserves” are estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The SEC permits publicly-reporting oil and gas companies to disclose “proved reserves” in their filings with the SEC. SEC rules also permit the disclosure of “probable” and possible” reserves. Rex Energy discloses proved reserves but does not disclose probable or possible reserves. We use certain broader terms such as “EUR” (estimated ultimate recovery of resources, defined below) and other descriptions of volumes of potentially recoverable hydrocarbons in this release. These broader classifications do not constitute “reserves” as defined by the SEC and we do not attempt to distinguish these classifications from probable or possible reserves as defined by SEC guidelines. We are prohibited from disclosing hydrocarbon quantities that do not constitute reserves in documents filed with the SEC.
We believe the data we prepared and supplied to our external reservoir engineers in connection with their preparation of the 12/31/12 reserve report, and the assumptions, forecasts, and estimates contained therein, are reasonable, however, we cannot assure that they will prove to have been correct. Estimates of reserves can be affected by inaccurate assumptions or by known or unknown risks and uncertainties.
We define EUR as the cumulative oil and gas production expected to be economically recovered from a reservoir or individual well from initial production until the end of its useful life. Our estimates of EURs have been prepared internally by our engineers and management without review by independent engineers. These estimates are by their nature more speculative than estimates of proved, probable, and possible reserves and accordingly are subject to substantially greater risk of being actually realized. Estimates of EURs and other figures may change significantly as development of our resource plays provide additional data and therefore actual quantities that may ultimately be recovered will likely differ materially from these estimates.
* * * * *
For more information, please contact:
Mark Aydin
Manager, Investor Relations
(814) 278-7249
maydin@rexenergy.com
10
REX ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
($ in Thousands, Except Share and Per Share Data)
| | | | | | | | |
| | | December 31, 2012 | | | December 31, 2011 | |
| ASSETS | | | | | | | | |
Current Assets | | | | | | | | |
Cash and Cash Equivalents | | $ | 43,975 | | | $ | 11,796 | |
Accounts Receivable | | | 24,980 | | | | 17,717 | |
Taxes Receivable | | | 6,429 | | | | 0 | |
Short-Term Derivative Instruments | | | 12,005 | | | | 10,404 | |
Assets Held For Sale | | | 2,279 | | | | 24,808 | |
Inventory, Prepaid Expenses and Other | | | 1,316 | | | | 1,191 | |
| | | | | | | | |
Total Current Assets | | | 90,984 | | | | 65,916 | |
Property and Equipment (Successful Efforts Method) | | | | | | | | |
Evaluated Oil and Gas Properties | | | 485,448 | | | | 349,938 | |
Unevaluated Oil and Gas Properties | | | 161,618 | | | | 123,241 | |
Other Property and Equipment | | | 50,073 | | | | 43,542 | |
Wells and Facilities in Progress | | | 96,798 | | | | 66,548 | |
Pipelines | | | 6,116 | | | | 4,408 | |
| | | | | | | | |
Total Property and Equipment | | | 800,053 | | | | 587,677 | |
Less: Accumulated Depreciation, Depletion and Amortization | | | (146,038 | ) | | | (107,433 | ) |
| | | | | | | | |
Net Property and Equipment | | | 654,015 | | | | 480,244 | |
Deferred Financing Costs and Other Assets – Net | | | 10,029 | | | | 3,405 | |
Equity Method Investments | | | 16,978 | | | | 41,683 | |
Long-Term Deferred Tax Asset | | | 0 | | | | 1,727 | |
Long-Term Derivative Instruments | | | 704 | | | | 8,576 | |
| | | | | | | | |
Total Assets | | $ | 772,710 | | | $ | 601,551 | |
| | | | | | | | |
| LIABILITIES AND EQUITY | | | | | | | | |
Current Liabilities | | | | | | | | |
Accounts Payable | | $ | 31,134 | | | $ | 41,558 | |
Accrued Expenses | | | 22,421 | | | | 15,682 | |
Short-Term Derivative Instruments | | | 1,389 | | | | 2,363 | |
Current Deferred Tax Liability | | | 539 | | | | 2,141 | |
Liabilities Related to Assets Held for Sale | | | 52 | | | | 1,622 | |
| | | | | | | | |
Total Current Liabilities | | | 55,535 | | | | 63,366 | |
8.875% Senior Notes Due 2020 | | | 250,000 | | | | 0 | |
Discount on Senior Notes | | | (1,742 | ) | | | 0 | |
Senior Secured Line of Credit and Long-Term Debt | | | 991 | | | | 225,138 | |
Long-Term Derivative Instruments | | | 1,510 | | | | 1,275 | |
Long-Term Deferred Tax Liability | | | 23,625 | | | | 84 | |
Other Deposits and Liabilities | | | 5,675 | | | | 744 | |
Future Abandonment Cost | | | 24,822 | | | | 18,670 | |
| | | | | | | | |
Total Liabilities | | | 360,416 | | | | 309,277 | |
Commitments and Contingencies | | | | | | | | |
Owners’ Equity | | | | | | | | |
Common Stock, $.001 par value per share, 100,000,000 shares authorized and 53,213,264 shares issued and outstanding on December 31, 2012 and 44,859,220 shares issued and outstanding on December 31, 2011 | | | 52 | | | | 44 | |
Additional Paid-In Capital | | | 451,062 | | | | 376,843 | |
Accumulated Deficit | | | (39,595 | ) | | | (84,888 | ) |
| | | | | | | | |
Rex Energy Owners’ Equity | | | 411,519 | | | | 291,999 | |
Noncontrolling Interests | | | 775 | | | | 275 | |
| | | | | | | | |
Total Owners’ Equity | | | 412,294 | | | | 292,274 | |
Total Liabilities and Owners’ Equity | | $ | 772,710 | | | $ | 601,551 | |
| | | | | | | | |
See accompanying notes to the consolidated financial statements
11
REX ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited, in Thousands, Except per Share Data)
| | | | | | | | | | | | | | | | |
| | | For the Three Months Ended
December 31, | | | For the Twelve Months Ended
December 31, | |
| | | 2012 | | | 2011 | | | 2012 | | | 2011 | |
OPERATING REVENUE | | | | | | | | | | | | | | | | |
Oil, Natural Gas and NGL Sales | | $ | 40,681 | | | $ | 30,792 | | | $ | 134,574 | | | $ | 111,879 | |
Field Services Revenue | | | 4,413 | | | | 838 | | | | 13,403 | | | | 2,518 | |
Other Revenue | | | 25 | | | | 51 | | | | 162 | | | | 209 | |
| | | | | | | | | | | | | | | | |
TOTAL OPERATING REVENUE | | | 45,119 | | | | 31,681 | | | | 148,139 | | | | 114,606 | |
OPERATING EXPENSES | | | | | | | | | | | | | | | | |
Production and Lease Operating Expense | | | 13,133 | | | | 9,061 | | | | 47,638 | | | | 33,116 | |
General and Administrative Expense | | | 5,302 | | | | 5,033 | | | | 23,345 | | | | 23,636 | |
(Gain) Loss on Disposal of Assets | | | (52 | ) | | | 38 | | | | 58 | | | | 502 | |
Impairment Expense | | | 17,228 | | | | 11,703 | | | | 20,585 | | | | 14,631 | |
Exploration Expense | | | 1,271 | | | | 304 | | | | 4,782 | | | | 2,507 | |
Depreciation, Depletion, Amortization and Accretion | | | 13,359 | | | | 8,720 | | | | 46,441 | | | | 28,361 | |
Field Services Operating Expense | | | 2,534 | | | | 113 | | | | 8,240 | | | | 1,750 | |
Other Operating Expense | | | 443 | | | | 903 | | | | 1,136 | | | | 819 | |
| | | | | | | | | | | | | | | | |
TOTAL OPERATING EXPENSES | | | 53,218 | | | | 35,875 | | | | 152,225 | | | | 105,322 | |
INCOME FROM OPERATIONS | | | (8,099 | ) | | | (4,194 | ) | | | (4,086 | ) | | | 9,284 | |
OTHER INCOME | | | | | | | | | | | | | | | | |
Interest Expense | | | (1,782 | ) | | | (986 | ) | | | (5,439 | ) | | | (2,009 | ) |
Gain on Derivatives, Net | | | 5,499 | | | | 6,128 | | | | 10,687 | | | | 18,916 | |
Other Income | | | 6,308 | | | | 17 | | | | 98,549 | | | | 79 | |
Income (Loss) on Equity Method Investments | | | (183 | ) | | | 246 | | | | (3,921 | ) | | | 81 | |
| | | | | | | | | | | | | | | | |
TOTAL OTHER INCOME | | | 9,842 | | | | 5,405 | | | | 99,876 | | | | 17,067 | |
| | | | |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX | | | 1,743 | | | | 1,211 | | | | 95,790 | | | | 26,351 | |
| | | | |
Income Tax Expense | | | (2,781 | ) | | | (62 | ) | | | (38,549 | ) | | | (8,270 | ) |
| | | | | | | | | | | | | | | | |
| | | | |
INCOME (LOSS) FROM CONTINUING OPERATIONS | | | (1,038 | ) | | | 1,149 | | | | 57,241 | | | | 18,081 | |
| | | | |
Loss From Discontinued Operations, Net of Income Taxes | | | (2,280 | ) | | | (4,263 | ) | | | (10,943 | ) | | | (33,457 | ) |
| | | | | | | | | | | | | | | | |
| | | | |
NET INCOME (LOSS) | | | (3,318 | ) | | | (3,114 | ) | | | 46,298 | | | | (15,376 | ) |
| | | | |
Net Income (Loss) Attributable to Noncontrolling Interests | | | 303 | | | | 7 | | | | 819 | | | | (7 | ) |
| | | | | | | | | | | | | | | | |
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY | | $ | (3,621 | ) | | $ | (3,121 | ) | | $ | 45,479 | | | $ | (15,369 | ) |
| | | | | | | | | | | | | | | | |
Earnings per common share: | | | | | | | | | | | | | | | | |
Basic – Net Income (Loss) From Continuing Operations Attributable to Rex Common Shareholders | | $ | (0.03 | ) | | $ | 0.03 | | | $ | 1.09 | | | $ | 0.41 | |
| | | | |
Basic – Net Loss From Discontinued Operations Attributable to Rex Common Shareholders | | | (0.04 | ) | | | (0.10 | ) | | | (0.21 | ) | | | (0.76 | ) |
| | | | | | | | | | | | | | | | |
| | | | |
Basic – Net Income (Loss) Attributable to Rex Common Shareholders | | $ | (0.07 | ) | | $ | (0.07 | ) | | $ | 0.88 | | | $ | (0.35 | ) |
| | | | | | | | | | | | | | | | |
| | | | |
Basic – Weighted Average Shares of Common Stock Outstanding | | | 52,278 | | | | 44,026 | | | | 51,543 | | | | 43,930 | |
| | | | |
Diluted – Net Income (Loss) From Continuing Operations Attributable to Rex Common Shareholders | | $ | (0.03 | ) | | $ | 0.03 | | | $ | 1.08 | | | $ | 0.41 | |
| | | | |
Diluted – Net Loss From Discontinued Operations Attributable to Rex Common Shareholders | | | (0.04 | ) | | | (0.10 | ) | | | (0.21 | ) | | | (0.76 | ) |
| | | | | | | | | | | | | | | | |
| | | | |
Diluted – Net Income (Loss) Attributable to Rex Common Shareholders | | $ | (0.07 | ) | | $ | (0.07 | ) | | $ | 0.87 | | | $ | (0.35 | ) |
| | | | | | | | | | | | | | | | |
| | | | |
Diluted – Weighted Average Shares of Common Stock Outstanding | | | 52,278 | | | | 44,567 | | | | 52,025 | | | | 44,476 | |
12
REX ENERGY CORPORATION
CONSOLIDATED OPERATIONAL HIGHLIGHTS
UNAUDITED
| | | | | | | | | | | | | | | | |
| | | Three Months Ending
December 31, | | | Twelve Months Ending
December 31, | |
| | | 2012 | | | 2011 | | | 2012 | | | 2011 | |
Oil, Natural Gas and NGL Sales (in thousands): | | | | | | | | | | | | | | | | |
Oil Sales | | $ | 17,742 | | | $ | 15,967 | | | $ | 66,329 | | | $ | 63,515 | |
Natural Gas Sales | | | 17,075 | | | | 11,943 | | | | 52,992 | | | | 38,161 | |
NGL Sales | | | 5,864 | | | | 2,882 | | | | 15,253 | | | | 10,203 | |
Cash Settled Derivatives: | | | | | | | | | | | | | | | | |
Oil | | | — | | | | (23 | ) | | | (286 | ) | | | (670 | ) |
Natural Gas | | | 2,701 | | | | 2,419 | | | | 16,095 | | | | 6,882 | |
NGL | | | 162 | | | | — | | | | 410 | | | | — | |
| | | | | | | | | | | | | | | | |
Total oil, natural gas and NGL sales including cash settled derivatives | | $ | 43,544 | | | $ | 33,188 | | | $ | 150,793 | | | $ | 118,091 | |
| | | | |
Production: | | | | | | | | | | | | | | | | |
Oil (Bbls) | | | 207,917 | | | | 176,529 | | | | 732,066 | | | | 694,452 | |
Natural Gas (Mcf) | | | 4,825,400 | | | | 3,144,088 | | | | 18,016,700 | | | | 8,912,250 | |
NGL (Bbls) | | | 121,479 | | | | 53,273 | | | | 358,049 | | | | 190,150 | |
| | | | | | | | | | | | | | | | |
Total Production (Mcfe)a | | | 6,801,776 | | | | 4,522,900 | | | | 24,557,390 | | | | 14,219,862 | |
| | | | |
Average Daily Production | | | | | | | | | | | | | | | | |
Oil (Bbls) | | | 2,260 | | | | 1,919 | | | | 2,000 | | | | 1,903 | |
Natural Gas (Mcf) | | | 52,450 | | | | 34,175 | | | | 49,226 | | | | 24,417 | |
NGL (Bbls) | | | 1,320 | | | | 579 | | | | 978 | | | | 521 | |
| | | | | | | | | | | | | | | | |
Total Production (Mcfe)a | | | 73,932 | | | | 49,162 | | | | 67,097 | | | | 38,956 | |
| | | | |
Average Price per Unit: | | | | | | | | | | | | | | | | |
Realized oil sales price per Bbl | | $ | 85.33 | | | $ | 90.45 | | | $ | 90.61 | | | $ | 91.46 | |
Realized impact of cash settled derivatives per Bbl | | | — | | | | (0.13 | ) | | | (0.39 | ) | | | (0.96 | ) |
| | | | | | | | | | | | | | | | |
Net realized price per Bbl | | $ | 85.33 | | | $ | 90.32 | | | $ | 90.22 | | | $ | 90.50 | |
| | | | |
Realized natural gas sales price per Mcf | | $ | 3.54 | | | $ | 3.80 | | | $ | 2.94 | | | $ | 4.28 | |
Realized impact of cash settled derivatives per Mcf | | | 0.56 | | | | 0.77 | | | | 0.89 | | | | 0.77 | |
| | | | | | | | | | | | | | | | |
Net realized price per Mcf | | $ | 4.10 | | | $ | 4.57 | | | $ | 3.83 | | | $ | 5.05 | |
| | | | |
Realized NGL sales price per Bbl | | $ | 48.27 | | | $ | 54.10 | | | $ | 42.60 | | | $ | 53.66 | |
Realized impact of cash settled derivatives per Bbl | | | 1.33 | | | | — | | | | 1.15 | | | | — | |
| | | | | | | | | | | | | | | | |
Net realized price per Bbl | | $ | 49.60 | | | $ | 54.10 | | | $ | 43.75 | | | $ | 53.66 | |
| | | | |
LOE/Mcfe | | $ | 1.93 | | | $ | 2.00 | | | $ | 1.94 | | | $ | 2.33 | |
| a | Oil and natural gas are converted at the rate of one barrel of oil equivalent to six Mcfe. |
13
REX ENERGY CORPORATION
COMMODITY DERIVATIVES – HEDGE POSITION AS OF FEBRUARY 22, 2013
| | | | | | | | |
| | | 2013 | | | 2014 | |
Oil Derivatives (Bbls) | | | | | | | | |
Swap Contracts | | | | | | | | |
Volume | | | 480,000 | | | | — | |
Price | | $ | 93.02 | | | | — | |
Collar Contracts | | | | | | | | |
Volume | | | 180,000 | | | | 60,000 | |
Ceiling | | $ | 104.33 | | | $ | 97.65 | |
Floor | | $ | 76.67 | | | $ | 90.00 | |
Collar Contracts with Short Puts | | | | | | | | |
Volume | | | 60,000 | | | | 360,000 | |
Ceiling | | $ | 100.00 | | | $ | 104.27 | |
Floor | | $ | 85.00 | | | $ | 80.00 | |
Short Put | | $ | 65.00 | | | $ | 65.00 | |
Put Spread Contracts | | | | | | | | |
Volume | | | — | | | | 168,000 | |
Floor | | $ | — | | | $ | 90.00 | |
Short Put | | $ | — | | | $ | 75.00 | |
Natural Gas Derivatives (Mcf) | | | | | | | | |
Swap Contracts | | | | | | | | |
Volume | | | 7,200,000 | | | | 3,240,000 | |
Price | | $ | 3.83 | | | $ | 3.86 | |
Swaption Contracts | | | | | | | | |
Volume | | | 1,200,000 | | | | — | |
Price | | $ | 4.50 | | | $ | — | |
Collar Contracts | | | | | | | | |
Volume | | | 3,360,000 | | | | 1,800,000 | |
Ceiling | | $ | 5.68 | | | $ | 4.43 | |
Floor | | $ | 4.77 | | | $ | 3.51 | |
Put Contracts | | | | | | | | |
Volume | | | 2,640,000 | | | | — | |
Floor | | $ | 5.00 | | | $ | — | |
Collar Contracts with Short Puts | | | | | | | | |
Volume | | | 2,520,000 | | | | 4,800,000 | |
Ceiling | | $ | 4.88 | | | $ | 4.68 | |
Floor | | $ | 4.17 | | | $ | 3.91 | |
Short Put | | $ | 3.35 | | | $ | 2.91 | |
Call Contracts | | | | | | | | |
Volume | | | — | | | | 1,800,000 | |
Ceiling | | $ | — | | | $ | 5.00 | |
Natural Gas Liquids (Bbls) | | | | | | | | |
Swap Contracts | | | | | | | | |
Propane (C3) | | | | | | | | |
Volume | | | 132,000 | | | | — | |
Price | | $ | 42.42 | | | | — | |
Butane (C4) | | | | | | | | |
Volume | | | 22,000 | | | | — | |
Price | | $ | 66.36 | | | | — | |
Isobutane (IC4) | | | | | | | | |
Volume | | | 21,000 | | | | — | |
Price | | $ | 69.72 | | | | — | |
Natural Gasoline (C5+) | | | | | | | | |
Volume | | | 79,000 | | | | 3,000 | |
Price | | $ | 88.62 | | | $ | 89.04 | |
14
APPENDIX
REX ENERGY CORPORATION
NON-GAAP MEASURES
EBITDAX
“EBITDAX” means, for any period, the sum of net income for such period plus the following expenses, charges or income to the extent deducted from or added to net income in such period: interest, income taxes, DD&A, unrealized losses from financial derivatives, the retroactive portion of the Pennsylvania Impact Fee, exploration expenses and other similar non-cash charges, minus all non-cash income, including but not limited to, income from unrealized financial derivatives, added to net income. EBITDAX, as defined above, is used as a financial measure by our management team and by other users of its financial statements, such as our commercial bank lenders to analyze such things as:
| | • | | Our operating performance and return on capital in comparison to those of other companies in our industry, without regard to financial or capital structure; |
| | • | | The financial performance of our assets and valuation of the entity without regard to financing methods, capital structure or historical cost basis; |
| | • | | Our ability to generate cash sufficient to pay interest costs, support our indebtedness and make cash distributions to our stockholders; and |
| | • | | The viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities. |
EBITDAX is not a calculation based on GAAP financial measures and should not be considered as an alternative to net income (loss) (the most directly comparable GAAP financial measure) in measuring our performance, nor should it be used as an exclusive measure of cash flows, because it does not consider the impact of working capital growth, capital expenditures, debt principal reductions, and other sources and uses of cash, which are disclosed in our consolidated statements of cash flows.
We have reported EBITDAX because it is a financial measure used by our existing commercial lenders, and because this measure is commonly reported and widely used by investors as an indicator of a company’s operating performance and ability to incur and service debt. You should carefully consider the specific items included in our computations of EBITDAX. While we have disclosed EBITDAX to permit a more complete comparative analysis of our operating performance and debt servicing ability relative to other companies, you are cautioned that EBITDAX as reported by us may not be comparable in all instances to EBITDAX as reported by other companies. EBITDAX amounts may not be fully available for management’s discretionary use, due to requirements to conserve funds for capital expenditures, debt service and other commitments.
We believe that EBITDAX assists our lenders and investors in comparing our performance on a consistent basis without regard to certain expenses, which can vary significantly depending upon accounting methods. Because we may borrow money to finance our operations, interest expense is a necessary element of our costs. In addition, because we use capital assets, DD&A are also necessary elements of our costs. Finally, we are required to pay federal and state taxes, which are necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations.
15
To compensate for these limitations, we believe it is important to consider both net income determined under GAAP and EBITDAX to evaluate our performance.
For purposes of consistency with current calculations, we have revised certain amounts relating to prior period EBITDAX. The following table presents a reconciliation of our net income to EBITDAX for each of the periods presented ($ in thousands):
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
December 31, | | | Twelve Months Ended
December 31, | |
| | | 2012 | | | 2011 | | | 2012 | | | 2011 | |
Net Income (Loss) From Continuing Operations | | $ | (1,038 | ) | | $ | 1,149 | | | $ | 57,241 | | | $ | 18,081 | |
Net (Income) Loss Attributable to Noncontrolling Interests | | | (303 | ) | | | (7 | ) | | | (819 | ) | | | 7 | |
| | | | | | | | | | | | | | | | |
Income (Loss) From Continuing Operations Attributable to Rex Energy | | $ | (1,341 | ) | | $ | 1,142 | | | $ | 56,422 | | | $ | 18,088 | |
Less Keystone Midstream Sale – First Escrow Payment | | | (7,168 | ) | | | — | | | | (7,168 | ) | | | — | |
Add Back Retroactive Portion of New Pennsylvania Impact Fee | | | — | | | | — | | | | 2,809 | | | | — | |
Add Back Depletion, Depreciation, Amortization and Accretion | | | 13,359 | | | | 8,720 | | | | 46,441 | | | | 28,361 | |
Add Back Non-Cash Compensation Expense | | | 993 | | | | 306 | | | | 3,140 | | | | 1,601 | |
Add Back Interest Expense | | | 1,782 | | | | 986 | | | | 5,439 | | | | 2,009 | |
Add Back Impairment Expense | | | 17,228 | | | | 11,703 | | | | 20,585 | | | | 14,631 | |
Add Back Exploration Expenses | | | 1,271 | | | | 304 | | | | 4,782 | | | | 2,507 | |
Add Back (Less) Loss (Gain) on Disposal of Assets | | | (52 | ) | | | 38 | | | | (92,181 | ) | | | 502 | |
Add Back (Less) Unrealized Loss (Gain) from Financial Derivatives | | | (2,635 | ) | | | (3,732 | ) | | | 5,532 | | | | (12,704 | ) |
Less Non-Cash Portion of Noncontrolling Interests | | | (42 | ) | | | (18 | ) | | | (140 | ) | | | (157 | ) |
Add Back Income Tax Expense | | | 2,781 | | | | 62 | | | | 38,549 | | | | 8,270 | |
Add Back Non-Cash Portion of Equity Method Investment | | | 177 | | | | 308 | | | | 4,471 | | | | 2,258 | |
| | | | | | | | | | | | | | | | |
EBITDAX From Continuing Operations | | $ | 26,353 | | | $ | 19,819 | | | $ | 88,681 | | | $ | 65,366 | |
Net Loss From Discontinued Operations | | | (2,281 | ) | | | (4,263 | ) | | | (10,943 | ) | | | (33,457 | ) |
Add Back Depletion, Depreciation, Amortization and Accretion | | | — | | | | 8 | | | | — | | | | 85 | |
Add Back (Less) Non-Cash Compensation Expense (Income) | | | — | | | | (21 | ) | | | (31 | ) | | | 24 | |
Add Back Interest Expense | | | — | | | | — | | | | — | | | | 1 | |
Add Back Impairment Expense | | | 6,819 | | | | 1,921 | | | | 19,770 | | | | 13,176 | |
Add Back Exploration Expenses | | | 57 | | | | 2,250 | | | | 867 | | | | 33,812 | |
Add Back (Less) Loss (Gain) on Disposal of Assets | | | (2,274 | ) | | | — | | | | (2,126 | ) | | | — | |
Less Income Tax Benefit | | | (2,425 | ) | | | (229 | ) | | | (8,489 | ) | | | (15,302 | ) |
| | | | | | | | | | | | | | | | |
Add EBITDAX From Discontinued Operations | | $ | (104 | ) | | $ | (334 | ) | | $ | (952 | ) | | $ | (1,661 | ) |
| | | | | | | | | | | | | | | | |
EBITDAX (Non-GAAP) | | $ | 26,249 | | | $ | 19,485 | | | $ | 87,729 | | | $ | 63,705 | |
| | | | | | | | | | | | | | | | |
16
Adjusted Net Income
“Adjusted Net Income” means, for any period, the sum of net income for the period plus the following expenses, charges or income, in each case, to the extent deducted from or added to net income in the period: unrealized losses from financial derivatives, non-cash compensation expense, dry hole expenses, disposals of assets, impairment and other one-time charges, minus all gains from unrealized financial derivatives, disposal of assets and deferred income tax benefits, added to net income. Adjusted Net Income is used as a financial measure by Rex Energy’s management team and by other users of its financial statements, to analyze its financial performance without regard to non-cash deferred taxes and non-cash unrealized losses or gains from oil and gas derivatives. Adjusted Net Income is not a calculation based on GAAP financial measures and should not be considered as an alternative to net income (loss) in measuring the company’s performance.
Rex Energy has reported Adjusted Net Income because it believes that this measure is commonly reported and widely used by investors as an indicator of a company’s operating performance. You should carefully consider the specific items included in the company’s computation of this measure. You are cautioned that Adjusted Net Income as reported by Rex Energy may not be comparable in all instances to that reported by other companies.
To compensate for these limitations, the company believes it is important to consider both net income determined under GAAP and Adjusted Net Income.
The following table presents a reconciliation of Rex Energy’s net income from continuing operations to its adjusted net income for each of the periods presented ($ in thousands):
| | | | | | | | | | | | | | | | |
| | | For the Three Months Ended
December 31, | | | For the Twelve Months Ended
December 31, | |
| | | 2012 | | | 2011 | | | 2012 | | | 2011 | |
Income From Continuing Operations Before Income Taxes, as reported | | $ | 1,743 | | | $ | 1,211 | | | $ | 95,790 | | | $ | 26,351 | |
Add Back Retroactive Portion of PA Impact Fee | | | — | | | | — | | | | 2,809 | | | | — | |
Add Back (Less) Unrealized Loss (Gain) from Financial Derivatives | | | (2,635 | ) | | | (3,732 | ) | | | 5,532 | | | | (12,704 | ) |
Less Installment Payment for Keystone Midstream Sale Escrow | | | (7,168 | ) | | | — | | | | (7,168 | ) | | | — | |
Add Back Impairment Expense | | | 17,228 | | | | 11,703 | | | | 20,585 | | | | 14,631 | |
Add Back Non-Cash Compensation Expense | | | 993 | | | | 306 | | | | 3,140 | | | | 1,601 | |
Add Back (Less) Loss (Gain) Loss on Disposal of Assets | | | 52 | | | | 38 | | | | (92,181 | ) | | | 502 | |
Add Back (Less) Loss (Income) Attributable to Noncontrolling Interests | | | (303 | ) | | | (7 | ) | | | (819 | ) | | | 7 | |
| | | | | | | | | | | | | | | | |
Adjusted Income Before Income Taxes | | $ | 9,910 | | | $ | 9,519 | | | $ | 27,688 | | | $ | 30,388 | |
Less Income Taxes, adjusted a | | | 3,944 | | | | 2,989 | | | | 11,020 | | | | 9,537 | |
| | | | | | | | | | | | | | | | |
Adjusted Net Income From Continuing Operations | | $ | 5,966 | | | $ | 6,530 | | | $ | 16,668 | | | $ | 20,851 | |
| | | | | | | | | | | | | | | | |
| | | | |
Adjusted Net Income Per Share – Basic | | $ | 0.11 | | | $ | 0.15 | | | $ | 0.32 | | | $ | 0.47 | |
Weighted Average Shares of Common Stock Outstanding – Basic | | | 52,278 | | | | 44,026 | | | | 51,543 | | | | 43,930 | |
| a | Income tax adjustment represents effective tax rate for the full year. |
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Finding and Development Cost
Finding and Development Cost per unit of production is a non-GAAP metric used by the industry, investors and analysts to measure the company’s ability to establish a long-term trend of adding reserves at a reasonable cost. Drill-Bit Finding and Development Cost is defined as the sum of total capital deployed, less lease acquisitions and other related expenditures, divided by total extensions and discoveries. All-In Finding and Development Cost is defined as the sum of total capital deployed divided by the sum of extensions, discoveries, acquisitions, divestitures, conversions, and revisions, less the prior period’s production. The calculations presented by the company are based on unaudited costs incurred excluding estimated abandonment costs. For purposes of consistency with current calculations, we have revised certain amounts relating to prior period Capital Deployed and Finding and Development Cost.
A tabular presentation of Drill-Bit and All-In Capital Deployed is included below ($ in millions):
| | | | | | | | | | | | |
| | | December 31,
2010 | | | December 31,
2011 | | | December 31,
2012 | |
Drill-Bit Capital Deployed | | $ | 76.3 | | | $ | 192.8 | | | $ | 176.9 | |
Acreage Acquisitions | | | 70.7 | | | | 78.7 | | | | 51.0 | |
Equity Method Investments, Noncontrolling Interests and Other | | | 17.5 | | | | 30.9 | | | | 11.0 | |
| | | | | | | | | | | | |
All-In Capital Deployed | | $ | 164.5 | | | $ | 302.4 | | | $ | 238.9 | |
A tabular presentation of Drill-Bit and All-In Finding and Development Costs is included below ($ in millions):
| | | | | | | | | | | | |
| | | December 31,
2010 | | | December 31,
2011 | | | December 31,
2012 | |
Drill-Bit Capital Deployed | | $ | 76.3 | | | $ | 192.8 | | | $ | 176.9 | |
Extensions and Discoveries (Bcfe) | | | 114.0 | | | | 155.8 | | | | 196.6 | |
Drill-Bit Finding and Development Cost ($/Mcfe) | | $ | 0.67 | | | $ | 1.24 | | | $ | 0.90 | |
| | | |
| | | December 31,
2010 | | | December 31,
2011 | | | December 31,
2012 | |
All-In Capital Deployed | | $ | 164.5 | | | $ | 302.4 | | | $ | 238.9 | |
| | | |
Extensions and Discoveries (Bcfe) | | | 114.0 | | | | 155.8 | | | | 196.6 | |
Production (Bcfe) | | | (7.4 | ) | | | (14.2 | ) | | | (24.6 | ) |
Acquisitions and Divestitures (Bcfe) | | | (14.5 | ) | | | — | | | | 0.3 | |
Revisions to Previous Estimates (Bcfe) | | | (15.8 | ) | | | 22.9 | | | | 79.6 | |
| | | | | | | | | | | | |
Subtotal (Bcfe) | | | 76.3 | | | | 164.5 | | | | 251.9 | |
| | | |
All-In Finding and Development Cost ($/Mcfe) | | $ | 2.15 | | | $ | 1.84 | | | $ | 0.95 | |
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PV-10
PV-10 represents the present value, discounted at 10% per annum, of estimated future net cash flows of our estimated proved reserves before income tax and asset retirement obligations of our estimated proved reserves. PV-10 is a non-GAAP financial measure because it excludes the effect of income taxes and asset retirement obligations. The most directly comparable GAAP measure is standardized measure of discounted future net cash flows. The standardized measure of discounted future net cash flows includes the effects of estimated future income tax expenses and asset retirement obligations and is calculated in accordance with Accounting Standards Topic 932. Standardized measure is based on proved reserves as of fiscal year-end calculated using the unweighted arithmetic average first-day-of-month prices for the prior 12 months. Rex believes that PV-10 is a useful measure for evaluating the relative value of our oil and natural gas properties. Rex also believes that investors and securities analysts may use PV-10 as a basis for comparison of the relative size and value of our reserves to other companies. Rex uses PV-10 as one measure of the value of the company’s proved reserves and to compare relative values of reserves among exploration and production companies without regard to income taxes or asset retirement obligations. Rex also uses this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10 should not be considered as an alternative to the standardized measure of discounted future net cash flows as computed under GAAP.
The following table presents a reconciliation of Rex Energy’s PV-10 to its standardized measure of discounted future net cash flows as of December 31, 2012:
| | | | |
| | | ($ in thousands) | |
Standardized Measure of Discounted Future Net Cash Flows | | $ | 396,123 | |
Discounted Future Cash Flows from Income Taxes1 | | | 79,587 | |
Discounted Future Cash Flows from Abandonments1 | | | 24,822 | |
| | | | |
Discounted Future Net Cash Flows (PV-10) | | $ | 500,532 | |
| 1 | For purposes of this reconciliation, we have used estimates of the effects of future income taxes and future abandonment costs (asset retirement obligations). These preliminary estimates may be revised in connection with the preparation of our audited financial statements for the year ended December 31, 2012. |
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