Attached files
| file | filename |
|---|---|
| 8-K - 8-K - EXCO RESOURCES INC | a8-5x13form8xk.htm |
Exhibit 99.1
EXCO Resources, Inc.
12377 Merit Drive, Suite 1700, LB 82, Dallas, Texas 75251
(214) 368-2084 FAX (972) 367-3559
EXCO RESOURCES, INC. REPORTS SECOND QUARTER
2013 RESULTS
DALLAS, TEXAS, August 5, 2013…EXCO Resources, Inc. (NYSE: XCO) (“EXCO”) today announced second quarter results for 2013.
– | Adjusted net income, a non-GAAP measure, was $0.10 per diluted share for the second quarter 2013 compared with $0.05 per diluted share for the second quarter 2012. The non-GAAP adjustments include gains from asset sales, non-cash gains or losses from derivative financial instruments (derivatives), non-cash ceiling test write-downs and other items typically not included by securities analysts in published estimates. |
– | Adjusted EBITDA for the second quarter 2013 was $90 million compared with $112 million for the second quarter 2012. Adjusted EBITDA is a non-GAAP measure and is computed using earnings before interest, taxes, depletion, depreciation and amortization, and is further adjusted using gains from asset sales, ceiling test write-downs and other non-cash income and expense items. |
– | GAAP results were net income of $86 million, or $0.40 per diluted share, for the second quarter 2013 compared with a net loss of $496 million, or $2.32 per diluted share, for the second quarter 2012. The second quarter 2012 net loss included a $429 million pre-tax non-cash ceiling test write-down of oil and natural gas properties. |
– | Oil, natural gas and natural gas liquids (NGL) production was 38 Bcfe, or 420 Mmcfe per day, for the second quarter 2013 compared with 50 Bcfe, or 550 Mmcfe per day in the second quarter 2012. The second quarter 2013 production from the East Texas/North Louisiana region was 328 Mmcfe per day compared with 483 Mmcfe per day in the second quarter 2012. The decrease in production was primarily the result of the contribution of conventional properties to the EXCO/HGI Partnership and normal production declines. The second quarter 2013 production in the Appalachia region was 64 Mmcfe per day compared with 41 Mmcfe per day in the second quarter 2012. The increase in production was due to our focus on completion activities in the Marcellus shale which resulted in 32 additional wells coming on line subsequent to the second quarter 2012. Our |
1
Exhibit 99.1
proportionate share of production from the EXCO/HGI Partnership was 28 Mmcfe per day in the second quarter 2013.
– | Oil, natural gas and NGL revenues, before cash settlements on derivatives, for the second quarter 2013 were $150 million compared with second quarter 2012 revenues of $118 million. Our average sales price per Mcfe increased to $3.93 per Mcfe for the second quarter 2013 from $2.36 per Mcfe for the second quarter 2012. When the impacts of cash settlements from derivatives are considered, oil, natural gas and NGL revenues were $151 million, or $3.95 per Mcfe in the second quarter 2013, compared with $180 million, or $3.60 per Mcfe in the second quarter 2012. |
– | Our direct operating costs were $0.31 per Mcfe for the second quarter 2013 compared with $0.38 per Mcfe for the second quarter 2012. We continue to focus on reducing our operating costs. Our second quarter 2013 operating costs per Mcfe were favorably impacted by the contribution of certain conventional properties to EXCO/HGI Partnership in the first quarter 2013. The conventional assets have higher operating costs than our shale assets. |
– | Our 50% share of TGGT's adjusted net income for the second quarter 2013 was $12 million compared with $16 million for the second quarter 2012. Our 50% share of TGGT's adjusted EBITDA was $18 million for the second quarter 2013 compared with $21 million for the second quarter 2012, after adjustments for certain non-cash items. |
– | On February 14, 2013, we formed the EXCO/HGI Partnership and contributed our conventional non-shale assets in East Texas and North Louisiana and our shallow Canyon Sand and other assets in the Permian Basin of West Texas. We received net proceeds of $575 million, after final purchase price adjustments, and a 25.5% economic interest in the partnership. The partnership also purchased certain shallow conventional assets from BG Group, plc (BG Group) for $131 million, after preliminary purchase price adjustments. The pro forma operating and financial information for the three and six months ended June 30, 2013 and 2012 is presented as if these transactions occurred on January 1, 2012 in a supplemental schedule to this press release. |
– | On July 2, 2013, we entered into definitive agreements with subsidiaries of Chesapeake Energy Corporation (Chesapeake) to acquire producing and undeveloped oil and natural gas assets in the Eagle Ford and Haynesville shale formations for an aggregate purchase price of approximately $1 billion, subject to customary purchase price adjustments. We closed the acquisition of the Haynesville assets on July 12, 2013 for $288 million, after customary preliminary purchase price adjustments, with an effective date of January 1, 2013. We closed the acquisition of the Eagle Ford assets on July 31, 2013 for $685 million, after customary preliminary purchase price adjustments, with an effective date of April 1, 2013. To facilitate the purchase of these assets, we amended our credit agreement which has an initial borrowing base of $1.6 billion including a $400 million asset sale requirement and a $300 million term loan. The asset sale requirement requires mandatory payments from proceeds of asset sales and must be repaid or refinanced within one year. |
In connection with the closing of the Eagle Ford assets, we entered into a participation agreement with affiliates of Kohlberg Kravis Roberts & Co. L.P. (KKR) to sell an undivided 50% interest in
2
Exhibit 99.1
the undeveloped acreage we acquired for $131 million in cash, after preliminary purchase price adjustments. After giving effect to the acquisition and the KKR payment, the credit agreement's initial borrowing base and the $400 million asset sale requirement were reduced by $131 million. We will jointly develop the Eagle Ford acreage with KKR under the participation agreement. Details of the acquisitions and terms of the KKR agreement are presented in the "Recent developments" section of this press release.
Douglas H. Miller, EXCO's Chief Executive Officer, commented, “We are executing on our strategy of acquiring assets in both our existing core areas and strategic new plays. Our recently announced acquisition in the Haynesville shale fortifies our leading position in that area. Our acquisition in the Eagle Ford in South Texas diversifies our portfolio by adding significant oil volumes with upside drilling opportunities. These acquisitions have significant levels of production which enhance our cash flow and borrowing base capacity. We have partnered with KKR to facilitate the drilling and development of approximately 300 undeveloped locations in the Eagle Ford acquisition which helps us prudently manage our capital expenditures and build long-term value for our shareholders.”
Adjusted net income
Our reported net income (loss) shown below, a GAAP measure, includes certain items not typically included by securities analysts in their published estimates of financial results. The following table provides a reconciliation of our net income (loss) to the non-GAAP measure of adjusted net income:
3
Exhibit 99.1
Three Months Ended | Six Months Ended | |||||||||||||||||||||||||||||||
June 30, 2013 | June 30, 2012 | June 30, 2013 | June 30, 2012 | |||||||||||||||||||||||||||||
(in thousands, except per share amounts) | Amount | Per share | Amount | Per share | Amount | Per share | Amount | Per share | ||||||||||||||||||||||||
Net income (loss), GAAP | $ | 85,598 | $ | (496,433 | ) | $ | 243,718 | $ | (778,082 | ) | ||||||||||||||||||||||
Adjustments: | ||||||||||||||||||||||||||||||||
Non-cash mark-to-market (gains) losses on derivative financial instruments | (54,452 | ) | 77,073 | 5,779 | 73,353 | |||||||||||||||||||||||||||
Non-cash write down of oil and natural gas properties | — | 428,801 | 10,707 | 704,665 | ||||||||||||||||||||||||||||
Adjustments included in equity (income) loss | 655 | — | 369 | 18,799 | ||||||||||||||||||||||||||||
(Gain) loss on divestitures and other non-recurring operating items | 3,041 | 6,673 | (181,345 | ) | 8,625 | |||||||||||||||||||||||||||
Deferred finance cost amortization acceleration | — | 3,000 | 3,535 | 3,000 | ||||||||||||||||||||||||||||
Income taxes on above adjustments (1) | 20,302 | (206,219 | ) | 64,382 | (323,377 | ) | ||||||||||||||||||||||||||
Adjustment to deferred tax asset valuation allowance (2) | (34,239 | ) | 198,573 | (97,487 | ) | 311,233 | ||||||||||||||||||||||||||
Total adjustments, net of taxes | (64,693 | ) | 507,901 | (194,060 | ) | 796,298 | ||||||||||||||||||||||||||
Adjusted net income | $ | 20,905 | $ | 11,468 | $ | 49,658 | $ | 18,216 | ||||||||||||||||||||||||
Net income (loss), GAAP (3) | $ | 85,598 | $ | 0.40 | $ | (496,433 | ) | $ | (2.32 | ) | $ | 243,718 | $ | 1.13 | $ | (778,082 | ) | $ | (3.63 | ) | ||||||||||||
Adjustments shown above (3) | (64,693 | ) | (0.30 | ) | 507,901 | 2.37 | (194,060 | ) | (0.90 | ) | 796,298 | 3.72 | ||||||||||||||||||||
Dilution attributable to share-based payments (4) | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||
Adjusted net income | $ | 20,905 | $ | 0.10 | $ | 11,468 | $ | 0.05 | $ | 49,658 | $ | 0.23 | $ | 18,216 | $ | 0.09 | ||||||||||||||||
Common stock and equivalents used for earnings per share (EPS): | ||||||||||||||||||||||||||||||||
Weighted average common shares outstanding | 214,788 | 214,164 | 214,786 | 214,154 | ||||||||||||||||||||||||||||
Dilutive stock options | 437 | — | — | — | ||||||||||||||||||||||||||||
Dilutive restricted shares | 798 | — | 561 | — | ||||||||||||||||||||||||||||
Shares used to compute diluted EPS for adjusted net income | 216,023 | 214,164 | 215,347 | 214,154 | ||||||||||||||||||||||||||||
(1) | The assumed income tax rate is 40% for all periods. |
(2) | Deferred tax valuation allowance has been adjusted to reflect the assumed income tax rate of 40% for all periods. |
(3) | Per share amounts are based on weighted average number of common shares outstanding. |
(4) | Represents dilution per share attributable to common share equivalents from in-the-money stock options and dilutive restricted shares calculated in accordance with the treasury stock method. |
Cash flow
Our cash flow from operations before changes in working capital and non-recurring other operating items was $77 million for the second quarter 2013. We primarily use our cash flow from operations and available
4
Exhibit 99.1
borrowing capacity in our credit agreement to fund our drilling and development programs and acquire producing properties. For the six months ended June 30, 2013, our cash flows from operations before changes in working capital and non-recurring items exceeded our capital expenditures by approximately $25 million.
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
(in thousands) | 2013 | 2012 | 2013 | 2012 | ||||||||||||
Cash flow from operations, GAAP | $ | 128,019 | $ | 135,345 | $ | 171,232 | $ | 280,468 | ||||||||
Net change in working capital | (53,585 | ) | (45,355 | ) | (18,595 | ) | (96,934 | ) | ||||||||
Non-recurring other operating items | 2,353 | 6,673 | 5,005 | 8,625 | ||||||||||||
Cash flow from operations before changes in working capital and non-recurring other operating items, non-GAAP measure (1) | $ | 76,787 | $ | 96,663 | $ | 157,642 | $ | 192,159 | ||||||||
(1) | Cash flow from operations before working capital changes and non-recurring other operating items are presented because management believes it is a useful financial indicator for companies in our industry. This non-GAAP disclosure is widely accepted as a measure of an oil and natural gas company’s ability to generate cash used to fund development and acquisition activities and service debt or pay dividends. Cash flow from operations before changes in working capital is not a measure of financial performance pursuant to GAAP and should not be used as an alternative to cash flows from operating, investing, or financing activities. Non-recurring other operating items have been excluded as they do not reflect our on-going operating activities. |
Recent developments
Haynesville shale acquisition
We closed the acquisition of the Haynesville assets from Chesapeake on July 12, 2013 for a purchase price of $288 million, after customary preliminary purchase price adjustments. The acquisition included certain producing and undeveloped oil and natural gas assets located in our core Haynesville shale operating area in Caddo Parish and DeSoto Parish, Louisiana. These properties included Chesapeake's non-operated interests in 170 wells operated by EXCO on approximately 5,600 net acres, and operated interests in 11 producing wells on approximately 4,000 net acres. The acquisition added approximately 55 identified drilling locations in the Haynesville shale formation to our drilling inventory. The Haynesville transaction provides strong base production and additional drilling inventory with upside development opportunities. Our internally generated engineered proved reserves, utilizing NYMEX strip prices and the January 1, 2013 effective date of the acquisition, are estimated to be 365 Bcfe. Recent net production from the properties averaged 114 Mmcfe per day. These assets are subject to BG Group's preferential right to acquire a 50% interest, which was formally offered to BG Group on July 13, 2013. Their election must be made within 60 days of our offer. If BG Group elects to participate, the proceeds, net of any applicable borrowing base assigned to the properties, will be used to reduce the bridge loan tranche of our credit agreement. Our development plans are to run up to three additional drilling rigs in manufacturing mode on recently acquired drilling locations by the end of 2013.
Eagle Ford shale acquisition
We closed the acquisition of the Eagle Ford assets from Chesapeake on July 31, 2013, for a purchase price of $685 million, after customary preliminary purchase price adjustments. The acquisition included certain
5
Exhibit 99.1
producing and undeveloped oil and natural gas assets in the Eagle Ford shale in the counties of Zavala, Dimmit, La Salle and Frio in South Texas. These properties include operated interests in 120 wells on approximately 55,000 net acres. The acquisition added approximately 300 identified drilling locations to our drilling inventory. In addition, we entered into a farm-out agreement with Chesapeake covering an additional 147,000 net acres adjacent to the acquired properties. Pursuant to the terms of the farm-out agreement, Chesapeake retains an overriding royalty interest in wells drilled on acreage covered by the farm-out agreement, with an option to convert the overriding royalty interest to a working interest at payout of the well. Our internally generated engineered proved reserves, utilizing NYMEX strip prices and the April 1, 2013 effective date of the acquisition, are estimated to be 29 Mmboe, with potential for 92 Mmboe with the development of the acquired assets. Recent net production from these properties averaged 6,100 Boe per day (85% oil). We also believe that additional upside exists in deeper formations such as the Buda and Pearsall, as well as shallow targets in the Austin Chalk and additional formations up hole.
KKR Participation Agreement
In connection with closing the Eagle Ford assets transaction, we entered into a participation agreement with KKR (KKR Participation Agreement) and sold an undivided 50% interest in the undeveloped acreage we acquired for approximately $131 million, after preliminary closing adjustments.
The KKR Participation Agreement provides that EXCO and KKR will jointly fund future development costs. With respect to each well drilled, EXCO will assign half of its undivided 50% interest in such well to KKR such that KKR will fund and own 75% of each well drilled and EXCO will fund and own 25% of each well drilled. When each quarterly tranche of wells drilled has been on production for one year, EXCO is required to offer to purchase KKR's 75% working interest at fair market value as defined in the KKR Participation Agreement, subject to specific well criteria and return hurdles. With respect to the first year (first four quarters) of the development program, we are required to make our first offer during the fourth quarter of 2014 for wells that have been on line for approximately one year.
There are currently three rigs drilling on the acquired Eagle Ford properties and our development plans for the remainder of 2013 include adding up to two more rigs. The development program will consist of manufacturing mode drilling, acreage retention focused drilling and pilot spacing drilling to test spacing between laterals. We expect to realize significant operational efficiencies by moving to a manufacturing mode development program in the play. With KKR, we expect to drill approximately 300 identified locations over a five year period including 30 wells during 2013.
Operations activity and outlook
We spent $49 million on development and exploitation activities, drilling and completing 18 gross (6.5 net) operated wells in the three months ended June 30, 2013. In addition, we participated in 3 gross (0.2 net) wells operated by others (OBO) during the second quarter 2013. We had an overall drilling success rate of 100% for the second quarter 2013.
Our actual capital expenditures for the six months ended June 30, 2013 are presented in the following table:
6
Exhibit 99.1
(in thousands) | Q1 2013 | Q2 2013 | YTD 2013 | |||||||||
Capital expenditures (1): | ||||||||||||
Development capital | $ | 58,715 | $ | 48,963 | $ | 107,678 | ||||||
Gas gathering and water pipelines | — | — | — | |||||||||
Lease acquisitions and seismic | — | 2,449 | 2,449 | |||||||||
Capitalized interest | 5,038 | 4,779 | 9,817 | |||||||||
Corporate and other | 4,596 | 4,310 | 8,906 | |||||||||
Total | $ | 68,349 | $ | 60,501 | $ | 128,850 | ||||||
(1) | Excludes capital expenditures related to our partnership with HGI. |
Our capital budget for the remainder of 2013 will be significantly impacted by the acquisitions of assets in the Eagle Ford and Haynesville shale formations. Management is currently finalizing our development plans and related capital expenditures for the remainder of 2013 as a result of these acquisitions.
Haynesville/Bossier Shale
As of June 30, 2013, our Haynesville/Bossier shale operated production was 971 Mmcf per day gross (283 Mmcf per day net) and with the addition of production from our OBO wells, we had 302 Mmcf per day of total net Haynesville/Bossier shale production. We operated three drilling rigs in the play during the second quarter 2013. We currently have 39 units fully developed in the Haynesville in DeSoto Parish. Including the 11 sections acquired from Chesapeake, we have an additional 40 units to be developed in our core DeSoto Parish area. We completed and turned to sales 15 gross (5.0 net) operated Haynesville horizontal wells in the quarter. We spud seven operated horizontal wells and participated in three OBO wells during the quarter. In total, we have 411 operated horizontal wells and 181 OBO horizontal wells flowing to sales.
Excluding the recently acquired drilling locations from Chesapeake, we plan to drill 26 gross (15.5 net) operated wells with our three-rig program for the full year 2013. Including completions carried into 2013 from wells drilled in late 2012, we plan to complete and turn to sales 42 gross (22.1 net) wells for the full year 2013. The drilling and completion activities on the recently acquired sections from Chesapeake are subject to a number of factors, including BG Group's election to participate in the acquisition and agreement on a related drilling program.
The average initial production rate from the 15 operated Haynesville horizontal wells completed and turned to sales in the second quarter 2013 in DeSoto Parish was 12,090 Mmcf per day with an average 7,389 psi flowing casing pressure on an average 18/64ths choke. This maximum choke size is indicative of our modified restricted choke management program in DeSoto Parish.
Our cost reduction and efficiency program is delivering positive results. We continue to see improvements in drilling times, stimulation costs and overall capital efficiency. Our current DeSoto Parish well costs are averaging approximately $7.7 million per well.
7
Exhibit 99.1
Marcellus Shale
Our gross operated Marcellus shale production at the end of the second quarter 2013 was 169 Mmcf per day (49 Mmcf per day net). Our focus through 2013 has been to complete and turn to sales our remaining drilled well inventory while reducing the size of our drilling program due to low natural gas prices. In the second quarter 2013, we spud two development wells in Central Pennsylvania and completed three gross operated (1.5 net) Marcellus wells in Central and Northeast Pennsylvania. During the remainder of 2013, we plan to turn to sales an additional 9 gross (3.2 net) Marcellus wells, two in our Central Pennsylvania area and seven in Northeast Pennsylvania. Our development planning for 2014 is underway and will be a combination of development drilling in our highest rate of return areas and selective appraisal drilling to delineate more of our acreage base.
In addition to the Marcellus shale production in Appalachia, we averaged 33 gross (14 net) operated Mmcfe per day of conventional production in the region.
EXCO/HGI Partnership
The following discussion of operating results, capital expenditures and planned operations addresses the EXCO/HGI Partnership in which we own a 25.5% economic interest.
Permian
During the second quarter 2013, the partnership drilled and completed 8 gross (7.9 net) wells in the Sugg Ranch area with 100% drilling success. Additionally, there was 1 gross (0.3 net) well successfully drilled in the Ackerly area in Dawson County. Economics for this drilling activity typically have high rates-of-return driven by oil and NGL content. The partnership expects to run one operated rig intermittently at Sugg Ranch for the remainder of 2013. At the end of the second quarter 2013, production from the 451 partnership wells averaged approximately 3,650 net Boe per day. This average production rate consisted of 1,240 net barrels of oil, 6,500 net Mcf of natural gas, and 1,320 net barrels of natural gas liquids per day.
East Texas/North Louisiana
The Vernon Field in Jackson Parish, Louisiana is the most significant producing field in this group of assets. At the end of the second quarter, net operated production averaged approximately 43 Mmcfe per day from the lower Cotton Valley and Bossier Sand formations. With current low commodity prices, the primary focus in the Vernon Field is to minimize our operating expense while maintaining production.
At the end of the second quarter, net operated production from other fields in East Texas/ North Louisiana averaged approximately 39 Mmcfe per day. Capital spending during the quarter was focused on maintaining our base production performance and on the recompletion of five wells in the Holly and Kingston fields with the addition of Cotton Valley and Hosston sands. During the remainder of the year, we will continue our recompletion program working on four additional wells.
8
Exhibit 99.1
In East Texas/North Louisiana, the EXCO/HGI Partnership currently has 915 wells flowing to sales with a total gross operated production rate of approximately 120 Mmcfe per day (82 Mmcfe per day net). In addition, net production from OBO wells averaged 2 Mmcfe per day.
TGGT
TGGT’s average throughput was approximately 1.3 Bcf per day during the second quarter 2013, compared with 1.5 Bcf per day in the second quarter 2012. TGGT's capital spending for the second quarter 2013 was $8 million. Capital spending has transitioned from major facility and pipeline projects to primarily installation of field infrastructure pipelines to support producer drilling activity in North Louisiana and East Texas.
Financial Data
Our consolidated balance sheets as of June 30, 2013 and December 31, 2012, consolidated statements of operations for the three and six months ended June 30, 2013 and 2012 and consolidated statements of cash flows for the six months ended June 30, 2013 and 2012, are included on the following pages. We have also included reconciliations of non-GAAP financial measures referred to in this press release.
EXCO will host a conference call on Tuesday, August 6, 2013 at 9:00 a.m. (Central time) to discuss the contents of this release and respond to questions. Please call (800) 309-5788 if you wish to participate, and ask for the EXCO conference call ID#14766051. The conference call will also be webcast on EXCO’s website at www.excoresources.com under the Investor Relations tab. Presentation materials related to this release will be posted, after market close, on EXCO’s website on Monday, August 5, 2013.
A digital recording will be available starting two hours after the completion of the conference call until August 20, 2013. Please call (800) 585-8367 and enter conference ID#14766051 to hear the recording. A digital recording of the conference call will also be available on EXCO’s website.
Additional information about EXCO Resources, Inc. may be obtained by contacting Chris Peracchi, EXCO’s Director of Finance and Investor Relations and Treasurer at EXCO’s headquarters, 12377 Merit Drive, Suite 1700, Dallas, TX 75251, telephone number (214) 368-2084, or by visiting EXCO’s website at www.excoresources.com. EXCO’s SEC filings and press releases can be found under the Investor Relations tab.
###
We believe that it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have no control. We caution users of the financial statements not to place undue reliance on a forward-looking statement. When considering our forward-looking statements, keep in mind the cautionary statements and the risk factors included in our Annual Report on Form 10-K for the year ended December 31, 2012, filed with the Securities and Exchange Commission, or the SEC, on February 21, 2013 and our other periodic filings with the SEC.
Our revenues, operating results and financial condition substantially depend on prevailing prices for oil and natural gas and the availability of capital from our credit agreement, or the EXCO Resources Credit Agreement. Declines in oil or natural gas prices may have a material adverse effect on our financial condition, liquidity, results of operations, the amount of oil or natural
9
Exhibit 99.1
gas that we can produce economically and the ability to fund our operations. Historically, oil and natural gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile.
The SEC permits oil and natural gas companies in filings made with the SEC to disclose proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. The SEC permits optional disclosure of “probable” and “possible” reserves in filings with the commission. EXCO may use broader terms to describe additional reserve opportunities such as “potential,” “unproved,” or “unbooked potential,” to describe volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC’s guidelines strictly prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved, probable or possible reserves and accordingly are subject to substantially greater risk of actually being realized by the company. While we believe our calculations of unproved drillsites and estimation of unproved reserves have been appropriately risked and are reasonable, such calculations and estimates have not been reviewed by third party engineers or appraisers. Investors are urged to consider closely the disclosure in our Annual Report on Form 10-K for the year ended December 31, 2012, which is available on our website at www.excoresources.com under the Investor Relations tab.
10
Exhibit 99.1
EXCO Resources, Inc.
Consolidated Balance Sheets
(in thousands) | June 30, 2013 | December 31, 2012 | ||||||
(Unaudited) | ||||||||
Assets | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 80,442 | $ | 45,644 | ||||
Restricted cash | 42,542 | 70,085 | ||||||
Accounts receivable, net: | ||||||||
Oil and natural gas | 78,029 | 84,348 | ||||||
Joint interest | 62,519 | 69,446 | ||||||
Other | 18,209 | 15,053 | ||||||
Inventory | 4,727 | 5,705 | ||||||
Derivative financial instruments | 33,082 | 49,500 | ||||||
Other | 16,767 | 22,085 | ||||||
Total current assets | 336,317 | 361,866 | ||||||
Equity investments | 371,190 | 347,008 | ||||||
Oil and natural gas properties (full cost accounting method): | ||||||||
Unproved oil and natural gas properties and development costs not being amortized | 367,407 | 470,043 | ||||||
Proved developed and undeveloped oil and natural gas properties | 2,699,608 | 2,715,767 | ||||||
Accumulated depletion | (2,029,922 | ) | (1,945,565 | ) | ||||
Oil and natural gas properties, net | 1,037,093 | 1,240,245 | ||||||
Gas gathering assets | 33,562 | 130,830 | ||||||
Accumulated depreciation and amortization | (9,688 | ) | (34,364 | ) | ||||
Gas gathering assets, net | 23,874 | 96,466 | ||||||
Office, field and other equipment, net | 17,597 | 20,725 | ||||||
Deferred financing costs, net | 18,098 | 22,584 | ||||||
Derivative financial instruments | 13,562 | 16,554 | ||||||
Goodwill | 163,155 | 218,256 | ||||||
Other assets | 28 | 28 | ||||||
Total assets | $ | 1,980,914 | $ | 2,323,732 | ||||
11
Exhibit 99.1
EXCO Resources, Inc.
Consolidated Balance Sheets
(in thousands, except per share and share data) | June 30, 2013 | December 31, 2012 | ||||||
(Unaudited) | ||||||||
Liabilities and shareholders’ equity | ||||||||
Current liabilities: | ||||||||
Accounts payable and accrued liabilities | $ | 81,134 | $ | 83,240 | ||||
Revenues and royalties payable | 131,519 | 134,066 | ||||||
Accrued interest payable | 17,311 | 17,029 | ||||||
Current portion of asset retirement obligations | 395 | 1,200 | ||||||
Income taxes payable | — | — | ||||||
Derivative financial instruments | 3,186 | 2,396 | ||||||
Total current liabilities | 233,545 | 237,931 | ||||||
Long-term debt | 1,310,407 | 1,848,972 | ||||||
Deferred income taxes | — | — | ||||||
Derivative financial instruments | 13,335 | 26,369 | ||||||
Asset retirement obligations and other long-term liabilities | 42,745 | 61,067 | ||||||
Commitments and contingencies | — | — | ||||||
Shareholders’ equity: | ||||||||
Preferred stock, $0.001 par value; 10,000,000 authorized shares; none issued and outstanding | — | — | ||||||
Common stock, $0.001 par value; 350,000,000 authorized shares; 217,906,792 shares issued and 217,367,571 shares outstanding at June 30, 2013; 218,126,071 shares issued and 217,586,850 shares outstanding at December 31, 2012 | 215 | 215 | ||||||
Additional paid-in capital | 3,209,517 | 3,200,067 | ||||||
Accumulated deficit | (2,821,371 | ) | (3,043,410 | ) | ||||
Treasury stock, at cost; 539,221 shares at June 30, 2013 and December 31, 2012 | (7,479 | ) | (7,479 | ) | ||||
Total shareholders’ equity | 380,882 | 149,393 | ||||||
Total liabilities and shareholders’ equity | $ | 1,980,914 | $ | 2,323,732 | ||||
12
Exhibit 99.1
EXCO Resources, Inc.
Consolidated Statements of Operations
(Unaudited)
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
(in thousands, except per share data) | 2013 | 2012 | 2013 | 2012 | ||||||||||||
Revenues: | ||||||||||||||||
Oil and natural gas | $ | 150,332 | $ | 117,978 | $ | 288,555 | $ | 252,826 | ||||||||
Costs and expenses: | ||||||||||||||||
Oil and natural gas operating costs | 11,902 | 18,863 | 25,519 | 41,659 | ||||||||||||
Production and ad valorem taxes | 3,981 | 6,789 | 9,229 | 13,982 | ||||||||||||
Gathering and transportation | 23,408 | 25,913 | 47,884 | 52,336 | ||||||||||||
Depletion, depreciation and amortization | 47,388 | 87,337 | 88,696 | 176,919 | ||||||||||||
Write-down of oil and natural gas properties | — | 428,801 | 10,707 | 704,665 | ||||||||||||
Accretion of discount on asset retirement obligations | 556 | 964 | 1,246 | 1,911 | ||||||||||||
General and administrative | 26,574 | 18,637 | 44,558 | 40,142 | ||||||||||||
(Gain) loss on divestitures and other operating items | 2,640 | 6,710 | (182,242 | ) | 8,335 | |||||||||||
Total costs and expenses | 116,449 | 594,014 | 45,597 | 1,039,949 | ||||||||||||
Operating income (loss) | 33,883 | (476,036 | ) | 242,958 | (787,123 | ) | ||||||||||
Other income (expense): | ||||||||||||||||
Interest expense | (15,105 | ) | (20,369 | ) | (35,297 | ) | (37,133 | ) | ||||||||
Gain (loss) on derivative financial instruments | 55,246 | (15,258 | ) | 11,732 | 38,607 | |||||||||||
Other income | 158 | 197 | 246 | 440 | ||||||||||||
Equity income | 11,416 | 15,033 | 24,079 | 7,127 | ||||||||||||
Total other income (expense) | 51,715 | (20,397 | ) | 760 | 9,041 | |||||||||||
Income (loss) before income taxes | 85,598 | (496,433 | ) | 243,718 | (778,082 | ) | ||||||||||
Income tax expense | — | — | — | — | ||||||||||||
Net income (loss) | $ | 85,598 | $ | (496,433 | ) | $ | 243,718 | $ | (778,082 | ) | ||||||
Earnings (loss) per common share: | ||||||||||||||||
Basic: | ||||||||||||||||
Net income (loss) | $ | 0.40 | $ | (2.32 | ) | $ | 1.13 | $ | (3.63 | ) | ||||||
Weighted average common shares outstanding | 214,788 | 214,164 | 214,786 | 214,154 | ||||||||||||
Diluted: | ||||||||||||||||
Net income (loss) | $ | 0.40 | $ | (2.32 | ) | $ | 1.13 | $ | (3.63 | ) | ||||||
Weighted average common shares and common share equivalents outstanding | 216,023 | 214,164 | 215,347 | 214,154 | ||||||||||||
13
Exhibit 99.1
EXCO Resources, Inc.
Consolidated Statements of Cash Flows
(Unaudited)
Six Months Ended June 30, | ||||||||
(in thousands) | 2013 | 2012 | ||||||
Operating Activities: | ||||||||
Net income (loss) | $ | 243,718 | $ | (778,082 | ) | |||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||
Depletion, depreciation and amortization | 88,696 | 176,919 | ||||||
Share-based compensation expense | 6,323 | 5,455 | ||||||
Accretion of discount on asset retirement obligations | 1,246 | 1,911 | ||||||
Write-down of oil and natural gas properties | 10,707 | 704,665 | ||||||
Income from equity investments | (24,079 | ) | (7,127 | ) | ||||
Non-cash change in fair value of derivatives | 5,779 | 73,353 | ||||||
Deferred income taxes | — | — | ||||||
Amortization of deferred financing costs and discount on the 2018 Notes | 6,597 | 6,440 | ||||||
Gain on divestitures | (186,350 | ) | — | |||||
Effect of changes in: | ||||||||
Accounts receivable | 17,728 | 107,693 | ||||||
Other current assets | (1,786 | ) | 4,997 | |||||
Accounts payable and other current liabilities | 2,653 | (15,756 | ) | |||||
Net cash provided by operating activities | 171,232 | 280,468 | ||||||
Investing Activities: | ||||||||
Additions to oil and natural gas properties, gathering systems and equipment | (132,363 | ) | (305,969 | ) | ||||
Property acquisitions | (33,390 | ) | (2,748 | ) | ||||
Equity method investments | (104 | ) | (10,254 | ) | ||||
Proceeds from disposition of property and equipment | 613,090 | 17,000 | ||||||
Restricted cash | 27,543 | 95,167 | ||||||
Net changes in advances from Appalachia JV | 8,276 | 5,193 | ||||||
Net cash provided by (used in) investing activities | 483,052 | (201,611 | ) | |||||
Financing Activities: | ||||||||
Borrowings under credit agreements | 46,757 | 53,000 | ||||||
Repayments under credit agreements | (644,541 | ) | (93,000 | ) | ||||
Proceeds from issuance of common stock | 42 | 297 | ||||||
Payment of common stock dividends | (21,479 | ) | (17,132 | ) | ||||
Deferred financing costs and other | (265 | ) | (1,623 | ) | ||||
Net cash used in financing activities | (619,486 | ) | (58,458 | ) | ||||
Net increase in cash | 34,798 | 20,399 | ||||||
Cash at beginning of period | 45,644 | 31,997 | ||||||
Cash at end of period | $ | 80,442 | $ | 52,396 | ||||
14
Exhibit 99.1
Supplemental Cash Flow Information: | ||||||||
Cash interest payments | $ | 37,059 | $ | 42,454 | ||||
Income tax payments | — | — | ||||||
Supplemental non-cash investing and financing activities: | ||||||||
Capitalized share-based compensation | $ | 3,055 | $ | 3,894 | ||||
Capitalized interest | 9,817 | 12,525 | ||||||
Issuance of common stock for director services | 38 | 527 | ||||||
Accrued restricted stock dividends | 201 | 190 | ||||||
EXCO/HGI Partnership debt upon formation, net | 58,613 | — | ||||||
15
Exhibit 99.1
EXCO Resources, Inc.
Consolidated EBITDA
And Adjusted EBITDA Reconciliations and Statement of Cash Flow Data
(Unaudited)
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
(in thousands) | 2013 | 2012 | 2013 | 2012 | ||||||||||||
Net income (loss) | $ | 85,598 | $ | (496,433 | ) | $ | 243,718 | $ | (778,082 | ) | ||||||
Interest expense | 15,105 | 20,369 | 35,297 | 37,133 | ||||||||||||
Income tax expense | — | — | — | — | ||||||||||||
Depletion, depreciation and amortization | 47,388 | 87,337 | 88,696 | 176,919 | ||||||||||||
EBITDA(1) | 148,091 | (388,727 | ) | 367,711 | (564,030 | ) | ||||||||||
Accretion of discount on asset retirement obligations | 556 | 964 | 1,246 | 1,911 | ||||||||||||
Non-cash write down of oil and natural gas properties | — | 428,801 | 10,707 | 704,665 | ||||||||||||
(Gain) loss on divestitures and other non-recurring operating items | 3,041 | 6,673 | (181,345 | ) | 8,625 | |||||||||||
Equity (income) loss | (11,416 | ) | (15,033 | ) | (24,079 | ) | (7,127 | ) | ||||||||
Non-cash change in fair value of derivative financial instruments | (54,452 | ) | 77,073 | 5,779 | 73,353 | |||||||||||
Share based compensation expense | 4,588 | 2,591 | 6,323 | 5,455 | ||||||||||||
Adjusted EBITDA (1) | $ | 90,408 | $ | 112,342 | $ | 186,342 | $ | 222,852 | ||||||||
Interest expense | (15,105 | ) | (20,369 | ) | (35,297 | ) | (37,133 | ) | ||||||||
Income tax expense | — | — | — | — | ||||||||||||
Amortization of deferred financing costs and discount on the 2018 Notes | 1,484 | 4,690 | 6,597 | 6,440 | ||||||||||||
Non-recurring other operating items | (2,353 | ) | (6,673 | ) | (5,005 | ) | (8,625 | ) | ||||||||
Changes in working capital | 53,585 | 45,355 | 18,595 | 96,934 | ||||||||||||
Net cash provided by operating activities | $ | 128,019 | $ | 135,345 | $ | 171,232 | $ | 280,468 | ||||||||
16
Exhibit 99.1
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
(in thousands) | 2013 | 2012 | 2013 | 2012 | ||||||||||||
Statement of cash flow data: | ||||||||||||||||
Cash flow provided by (used in): | ||||||||||||||||
Operating activities | $ | 128,019 | $ | 135,345 | $ | 171,232 | $ | 280,468 | ||||||||
Investing activities | (42,208 | ) | (33,723 | ) | 483,052 | (201,611 | ) | |||||||||
Financing activities | (32,014 | ) | (79,797 | ) | (619,486 | ) | (58,458 | ) | ||||||||
Other financial and operating data: | ||||||||||||||||
EBITDA(1) | $ | 148,091 | $ | (388,727 | ) | $ | 367,711 | $ | (564,030 | ) | ||||||
Adjusted EBITDA(1) | 90,408 | 112,342 | 186,342 | 222,852 | ||||||||||||
(1) | Earnings before interest, taxes, depreciation, depletion and amortization, or “EBITDA” represents net income adjusted to exclude interest expense, income taxes and depreciation, depletion and amortization. “Adjusted EBITDA” represents EBITDA adjusted to exclude non-recurring other operating items, accretion of discount on asset retirement obligations, non-cash changes in the fair value of derivatives, non-cash write-downs of assets, stock-based compensation and income or losses from equity method investments. We have presented EBITDA and Adjusted EBITDA because they are a widely used measure by investors, analysts and rating agencies for valuations, peer comparisons and investment recommendations. In addition, these measures are used in covenant calculations required under our credit agreement and the indenture governing our 7.5% senior notes due September 15, 2018. Compliance with the liquidity and debt incurrence covenants included in these agreements is considered material to us. Our computations of EBITDA and Adjusted EBITDA may differ from computations of similarly titled measures of other companies due to differences in the inclusion or exclusion of items in our computations as compared to those of others. EBITDA and Adjusted EBITDA are measures that are not prescribed by generally accepted accounting principles, or GAAP. EBITDA and Adjusted EBITDA specifically exclude changes in working capital, capital expenditures and other items that are set forth on a cash flow statement presentation of a company’s operating, investing and financing activities. As such, we encourage investors not to use these measures as substitutes for the determination of net income, net cash provided by operating activities or other similar GAAP measures. |
17
Exhibit 99.1
TGGT Holdings, LLC
EBITDA and Adjusted EBITDA Reconciliation
(Unaudited)
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
(in thousands) | 2013 | 2012 | 2013 | 2012 | ||||||||||||
Equity income (loss) | $ | 11,416 | $ | 15,033 | $ | 24,079 | $ | 7,127 | ||||||||
Amortization of the difference in the historical basis of our contribution to TGGT | (402 | ) | (402 | ) | (804 | ) | (804 | ) | ||||||||
Equity loss of other investments | 96 | 1,715 | 287 | 2,594 | ||||||||||||
EXCO's share of TGGT net income (loss) | 11,110 | 16,346 | 23,562 | 8,917 | ||||||||||||
BG Group's share of TGGT net income (loss) | 11,110 | 16,346 | 23,562 | 8,917 | ||||||||||||
TGGT net income (loss) | 22,220 | 32,692 | 47,124 | 17,834 | ||||||||||||
Interest expense | 3,083 | 2,683 | 6,423 | 6,557 | ||||||||||||
Margin tax expense | 112 | 30 | 222 | 268 | ||||||||||||
Depreciation and amortization | 8,935 | 6,942 | 17,693 | 14,823 | ||||||||||||
TGGT EBITDA(1) | 34,350 | 42,347 | 71,462 | 39,482 | ||||||||||||
Asset impairments and non-recurring other operating items | 1,309 | — | 738 | 37,598 | ||||||||||||
TGGT Adjusted EBITDA(1) | $ | 35,659 | $ | 42,347 | $ | 72,200 | $ | 77,080 | ||||||||
EXCO's share of TGGT Adjusted EBITDA (2) | $ | 17,830 | $ | 21,174 | $ | 36,100 | $ | 38,540 | ||||||||
(1) | Earnings before interest, taxes, depreciation, depletion and amortization, or “EBITDA” represents net income adjusted to exclude interest expense, income taxes and depreciation and amortization. “Adjusted EBITDA” represents EBITDA adjusted to exclude asset impairments, gains and losses on divestitures and non-recurring other operating items. We have presented EBITDA and Adjusted EBITDA because they are a widely used measure by investors, analysts and rating agencies for valuations, peer comparisons and investment recommendations. Our computations of EBITDA and Adjusted EBITDA may differ from computations of similarly titled measures of other companies due to differences in the inclusion or exclusion of items in our computations as compared to those of others. EBITDA and Adjusted EBITDA are measures that are not prescribed by generally accepted accounting principles, or GAAP. EBITDA and Adjusted EBITDA specifically exclude changes in working capital, capital expenditures and other items that are set forth on a cash flow statement presentation of a company’s operating, investing and financing activities. As such, we encourage investors not to use these measures as substitutes for the determination of net income, net cash provided by operating activities or other similar GAAP measures. |
(2) | Represents our 50% equity share in TGGT. |
18
Exhibit 99.1
TGGT Holdings, LLC
Computation of Adjusted Net Income
(Unaudited)
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
(in thousands) | 2013 | 2012 | 2013 | 2012 | ||||||||||||
Net income (loss), GAAP | $ | 22,220 | $ | 32,692 | $ | 47,124 | $ | 17,834 | ||||||||
Adjustments: | ||||||||||||||||
(Gain) loss on asset disposal | (28 | ) | — | 162 | 1,399 | |||||||||||
Asset impairment, net of insurance recoveries | 983 | — | 1,247 | 35,343 | ||||||||||||
Other non-cash items | 354 | — | (671 | ) | 856 | |||||||||||
Total adjustments | 1,309 | — | 738 | 37,598 | ||||||||||||
Adjusted net income | $ | 23,529 | $ | 32,692 | $ | 47,862 | $ | 55,432 | ||||||||
EXCO's 50% share of TGGT's adjusted net income (1) | $ | 11,765 | $ | 16,346 | $ | 23,931 | $ | 27,716 | ||||||||
(1) | TGGT’s net income, computed in accordance with GAAP, includes certain items not typically included by securities analysts in published estimates of financial results. This table provides a reconciliation of GAAP net income to a non-GAAP measure of adjusted net income. |
19
Exhibit 99.1
EXCO Resources, Inc.
Summary of Operating Data
(Unaudited)
Three Months Ended | Six Months Ended | |||||||||||||||||||||
June 30, | % | June 30, | % | |||||||||||||||||||
2013 | 2012 | Change | 2013 | 2012 | Change | |||||||||||||||||
Production: | ||||||||||||||||||||||
Oil (Mbbls) | 50 | 182 | (73 | )% | 152 | 374 | (59 | )% | ||||||||||||||
Natural gas liquids (Mbbls) | 43 | 131 | (67 | )% | 125 | 253 | (51 | )% | ||||||||||||||
Natural gas (Mmcf) | 37,695 | 48,162 | (22 | )% | 77,288 | 95,154 | (19 | )% | ||||||||||||||
Total production (Mmcfe) (1) | 38,253 | 50,040 | (24 | )% | 78,950 | 98,916 | (20 | )% | ||||||||||||||
Average daily production (Mmcfe) | 420 | 550 | (24 | )% | 436 | 543 | (20 | )% | ||||||||||||||
Average sales price (before cash settlements of derivative financial instruments): | ||||||||||||||||||||||
Oil (per Bbl) | $ | 90.48 | $ | 86.38 | 5 | % | $ | 84.59 | $ | 91.90 | (8 | )% | ||||||||||
Natural gas liquids (per Bbl) | 33.98 | 40.15 | (15 | )% | 36.43 | 46.30 | (21 | )% | ||||||||||||||
Natural gas (per Mcf) | 3.83 | 2.01 | 91 | % | 3.51 | 2.17 | 62 | % | ||||||||||||||
Natural gas equivalent (per Mcfe) | 3.93 | 2.36 | 67 | % | 3.65 | 2.56 | 43 | % | ||||||||||||||
Costs and expenses (per Mcfe): | ||||||||||||||||||||||
Oil and natural gas operating costs | $ | 0.31 | $ | 0.38 | (18 | )% | $ | 0.32 | $ | 0.42 | (24 | )% | ||||||||||
Production and ad valorem taxes | 0.10 | 0.14 | (29 | )% | 0.12 | 0.14 | (14 | )% | ||||||||||||||
Gathering and transportation | 0.61 | 0.52 | 17 | % | 0.61 | 0.53 | 15 | % | ||||||||||||||
Depletion | 1.19 | 1.67 | (29 | )% | 1.07 | 1.71 | (37 | )% | ||||||||||||||
Depreciation and amortization | 0.05 | 0.08 | (38 | )% | 0.05 | 0.08 | (38 | )% | ||||||||||||||
General and administrative | 0.69 | 0.37 | 86 | % | 0.56 | 0.41 | 37 | % | ||||||||||||||
20
Exhibit 99.1
Selected EXCO/HGI Partnership Information
(Unaudited)
Three months ended June 30, 2013 | Three months ended June 30, 2012 | |||||||||||||||||||||||
(dollars in thousands, except per unit rate) | Historical EXCO | Pro forma adjustments (1) | Pro forma EXCO | Historical EXCO | Pro forma adjustments (1) | Pro forma EXCO | ||||||||||||||||||
Production: | ||||||||||||||||||||||||
Total production (Mmcfe) | 38,253 | — | 38,253 | 50,040 | (6,361 | ) | 43,679 | |||||||||||||||||
Average production (Mmcfe/d) | 420 | — | 420 | 550 | (70 | ) | 480 | |||||||||||||||||
Revenues: | ||||||||||||||||||||||||
Revenues, excluding derivatives | $ | 150,332 | $ | — | $ | 150,332 | $ | 117,978 | $ | (25,156 | ) | $ | 92,822 | |||||||||||
Average realized price ($/Mcfe) | 3.93 | — | 3.93 | 2.36 | 3.95 | 2.13 | ||||||||||||||||||
Expenses: | ||||||||||||||||||||||||
Direct operating costs | $ | 11,902 | $ | — | $ | 11,902 | $ | 18,863 | $ | (7,415 | ) | $ | 11,448 | |||||||||||
Per Mcfe | 0.31 | — | 0.31 | 0.38 | 1.17 | 0.26 | ||||||||||||||||||
Production and ad valorem taxes | 3,981 | — | 3,981 | 6,789 | (3,244 | ) | 3,545 | |||||||||||||||||
Per Mcfe | 0.10 | — | 0.10 | 0.14 | 0.51 | 0.08 | ||||||||||||||||||
Gathering and transportation | 23,408 | — | 23,408 | 25,913 | (1,745 | ) | 24,168 | |||||||||||||||||
Per Mcfe | 0.61 | — | 0.61 | 0.52 | 0.27 | 0.55 | ||||||||||||||||||
Excess of revenues over operating expenses | $ | 111,041 | $ | — | $ | 111,041 | $ | 66,413 | $ | (12,752 | ) | $ | 53,661 | |||||||||||
Six months ended June 30, 2013 | Six months ended June 30, 2012 | |||||||||||||||||||||||
(dollars in thousands, except per unit rate) | Historical EXCO | Pro forma adjustments (1) | Pro forma EXCO | Historical EXCO | Pro forma adjustments (1) | Pro forma EXCO | ||||||||||||||||||
Production: | ||||||||||||||||||||||||
Total production (Mmcfe) | 78,950 | (2,705 | ) | 76,245 | 98,916 | (12,967 | ) | 85,949 | ||||||||||||||||
Average production (Mmcfe/d) | 436 | (15 | ) | 421 | 543 | (71 | ) | 472 | ||||||||||||||||
Revenues: | ||||||||||||||||||||||||
Revenues, excluding derivatives | $ | 288,555 | $ | (12,657 | ) | $ | 275,898 | $ | 252,826 | $ | (55,914 | ) | $ | 196,912 | ||||||||||
Average realized price ($/Mcfe) | 3.65 | 4.68 | 3.62 | 2.56 | 4.31 | 2.29 | ||||||||||||||||||
Expenses: | ||||||||||||||||||||||||
Direct operating costs | $ | 25,519 | $ | (3,489 | ) | $ | 22,030 | $ | 41,659 | $ | (15,835 | ) | $ | 25,824 | ||||||||||
Per Mcfe | 0.32 | 1.29 | 0.29 | 0.42 | 1.22 | 0.30 | ||||||||||||||||||
Production and ad valorem taxes | 9,229 | (1,545 | ) | 7,684 | 13,982 | (6,775 | ) | 7,207 | ||||||||||||||||
Per Mcfe | 0.12 | 0.57 | 0.10 | 0.14 | 0.52 | 0.08 | ||||||||||||||||||
Gathering and transportation | 47,884 | (782 | ) | 47,102 | 52,336 | (4,247 | ) | 48,089 | ||||||||||||||||
Per Mcfe | 0.61 | 0.29 | 0.62 | 0.53 | 0.33 | 0.56 | ||||||||||||||||||
Excess of revenues over operating expenses | $ | 205,923 | $ | (6,841 | ) | $ | 199,082 | $ | 144,849 | $ | (29,057 | ) | $ | 115,792 | ||||||||||
(1) | The 2013 pro forma adjustments reflect the contribution of our interest in certain properties from January l, 2013 to February 14, 2013 and the acquisition of certain shallow conventional assets from BG Group from January 1, 2013 to March 5, 2013. The 2012 pro forma adjustments reflect the impact of these transactions from January 1, 2012 to June 30, 2012. |
21