x
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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Texas
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74-1492779
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(State or other jurisdiction of incorporation or organization)
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(I.R.S. Employer Identification No.)
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12377 Merit Drive
Suite 1700, LB 82
Dallas, Texas
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75251
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(Address of principal executive offices)
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(Zip Code)
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Title of each class
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Name of each exchange on which registered
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Common Shares, $0.001 par value
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New York Stock Exchange
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Large accelerated filer
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x
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Accelerated filer
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o
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Non-accelerated filer
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o
(Do not check if a smaller reporting company)
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Smaller reporting company
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o
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•
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East Texas and North Louisiana - we currently hold approximately 85,300 net acres in the Haynesville and Bossier shales;
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•
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South Texas - we currently hold approximately 52,900 net acres in the Eagle Ford shale; and
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•
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Appalachia - we currently hold approximately 157,000 net acres prospective in the Marcellus shale.
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•
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closed a rights offering and related private placement of our common shares ("Rights Offering") on January 17, 2014, which resulted in the issuance of 54,574,734 shares of our common shares for gross proceeds of $272.9 million;
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•
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sold our interest in certain non-operated assets in the Permian Basin, including producing wells and undeveloped acreage, for approximately
$68.2 million
;
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•
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completed a public offering of $500.0 million in aggregate principal amount of senior unsecured notes due April 15, 2022 ("2022 Notes"). We received net proceeds of approximately $490.0 million after offering fees and expenses; and
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•
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sold our entire interest in Compass Production Partners, L.P. ("Compass") for $118.8 million in cash.
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•
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multi-year inventory of development drilling and exploitation projects;
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•
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high drilling success rates;
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•
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significant unproved reserves and resources; and
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•
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long reserve lives.
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Areas
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Total Proved Reserves (Bcfe) (1)
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PV-10 (in millions) (1) (2)
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Average daily net production (Mmcfe) (3)
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||||
East Texas/North Louisiana
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881.2
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$
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813.8
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238
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South Texas (4)
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113.1
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561.5
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39
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Appalachia and other
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269.5
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167.3
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55
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Total
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1,263.8
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$
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1,542.6
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332
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Areas
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Estimated drilling locations (5)
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Total gross acreage
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Total net acreage
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|||
East Texas/North Louisiana
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1,988
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230,600
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99,300
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South Texas (6)
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212
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101,400
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52,900
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Appalachia and other
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4,194
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659,400
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297,100
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Total
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6,394
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991,400
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449,300
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(1)
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The total Proved Reserves and PV-10 as of
December 31, 2014
were prepared in accordance with the rules and regulations of the Securities and Exchange Commission ("SEC"). The estimated future plugging and abandonment costs necessary to compute PV-10 were computed internally.
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(2)
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The PV-10 data used in this table was based on reference prices using the simple average of the spot prices for the trailing 12 month period using the first day of each month beginning on January 1,
2014
and ending on December 1,
2014
, of
$4.35
per Mmbtu for natural gas and
$94.99
per Bbl for oil, in each case adjusted for geographical and historical differentials. The price for NGLs was
$33.03
per barrel and was computed on the trailing 12 month average of realized prices. Market prices for oil, natural gas and NGLs are volatile (see “Item 1A. Risk Factors-Risks Relating to Our Business”). We believe that PV-10, while not a financial measure in accordance with generally accepted accounting principles in the United States ("GAAP"), is an important financial measure used by investors and independent oil and natural gas producers for evaluating the relative significance of oil and natural gas properties and acquisitions due to tax characteristics which can differ significantly among comparable companies. The total Standardized Measure, a measure recognized under GAAP, as of
December 31, 2014
was
$1.5 billion
. The Standardized Measure represents the PV-10 after giving effect to income taxes, and is calculated in accordance with the Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") 932,
Extractive Activities, Oil and Gas
("ASC 932"). Our existing net operating loss carryforwards eliminated estimated future income taxes for the year ended
December 31, 2014
. The amount of estimated future plugging and abandonment costs, the PV-10 of these costs and the Standardized Measure were determined by us. We do not designate our derivative financial instruments as hedges and accordingly, do not include the impact of derivative financial instruments when computing the Standardized Measure.
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(3)
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The average daily net production rate was calculated based on the average daily rate during the final month of the year ended
December 31, 2014
.
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(4)
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We are developing certain undeveloped acreage in the Eagle Ford shale pursuant to the Participation Agreement. Under this agreement, we assign half of our working interest in a well to the joint venture partner upon commencement of development. Therefore, we have only included half of our current working interest in the undeveloped locations subject to this agreement within our Proved Reserves. We have not incorporated the impact of future acquisitions under the Participation Agreement within our Proved Reserves.
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(5)
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Identified drilling locations represent total gross drilling locations identified and scheduled by our management as an estimate of our multi-year drilling activities on existing acreage. Our actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, drilling results and other factors (see “Item 1A. Risk Factors-Risks Relating To Our Business”).
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(6)
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The acreage in this region includes 41,600 net acres outside of our core area in Zavala County that are subject to our joint venture partner's right to participate in each proposed well. The acreage outside of our core area is not subject to the Participation Agreement.
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As of December 31,
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||||||||||
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2014
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2013
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2012
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||||||
Oil (Mbbls)
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||||||
Developed
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14,429
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11,274
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4,371
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|||
Undeveloped
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3,258
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4,104
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1,199
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|||
Total
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17,687
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15,378
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5,570
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|||
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||||||
Natural gas (Mmcf)
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||||||
Developed
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502,314
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657,116
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917,326
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|||
Undeveloped
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652,714
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359,363
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18,806
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|||
Total
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1,155,028
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1,016,479
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936,132
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|||
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||||||
Natural gas liquids (Mbbls)
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||||||
Developed
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387
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2,088
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4,784
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|||
Undeveloped
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54
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495
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1,855
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|||
Total
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441
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2,583
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6,639
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|||
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||||||
Equivalent reserves (Mmcfe)
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|
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||||||
Developed
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591,210
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737,291
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972,256
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|||
Undeveloped
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672,586
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386,954
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37,130
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|||
Total
|
|
1,263,796
|
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1,124,245
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1,009,386
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|||
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||||||
PV-10 (in millions) (1)
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||||||
Developed
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$
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1,117.6
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$
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1,153.5
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$
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666.0
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Undeveloped
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425.0
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98.8
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30.1
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|||
Total
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$
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1,542.6
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$
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1,252.3
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$
|
696.1
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|
|
|
|
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||||||
Standardized Measure (in millions) (2)
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$
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1,542.6
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$
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1,252.3
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|
$
|
696.1
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(1)
|
The PV-10 is based on the following average spot prices, in each case adjusted for historical differentials. Prices presented on the table below are the trailing 12 month simple average spot price at the first of the month for natural gas at Henry Hub and West Texas Intermediate crude oil at Cushing, Oklahoma. Our NGL price was computed using the trailing 12 month average of realized prices.
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Average spot prices
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||||||||||
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Oil (per Bbl)
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Natural gas (per Mmbtu)
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|
Natural gas liquids (per Bbl)
|
||||||
December 31, 2014
|
|
$
|
94.99
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|
|
$
|
4.35
|
|
|
$
|
33.03
|
|
December 31, 2013
|
|
96.78
|
|
|
3.67
|
|
|
39.92
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|
|||
December 31, 2012
|
|
94.71
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|
|
2.76
|
|
|
46.57
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(2)
|
There is no difference in Standardized Measure and PV-10 for all years presented as the impacts of net operating loss carry-forwards eliminated future income taxes.
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Oil (Mbbls)
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Natural gas (Mmcf)
|
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Natural gas liquids (Mbbls)
|
|
Equivalent natural gas (Mmcfe)
|
||||
Proved Developed Reserves
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14,429
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|
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502,314
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|
|
387
|
|
|
591,210
|
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Proved Undeveloped Reserves
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3,258
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|
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652,714
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|
54
|
|
|
672,586
|
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Total Proved Reserves (1)
|
|
17,687
|
|
|
1,155,028
|
|
|
441
|
|
|
1,263,796
|
|
The changes in reserves for the year are as follows:
|
|
|
|
|
|
|
|
|
||||
January 1, 2014
|
|
15,378
|
|
|
1,016,479
|
|
|
2,583
|
|
|
1,124,245
|
|
Purchases of reserves in place
|
|
—
|
|
|
7,316
|
|
|
—
|
|
|
7,316
|
|
Discoveries and extensions
|
|
4,164
|
|
|
69,902
|
|
|
107
|
|
|
95,528
|
|
Revisions of previous estimates (2):
|
|
|
|
|
|
|
|
|
||||
Changes in price
|
|
45
|
|
|
167,302
|
|
|
127
|
|
|
168,334
|
|
Other factors
|
|
1,737
|
|
|
120,850
|
|
|
(8
|
)
|
|
131,224
|
|
Sales of reserves in place
|
|
(1,401
|
)
|
|
(105,841
|
)
|
|
(2,144
|
)
|
|
(127,111
|
)
|
Production
|
|
(2,236
|
)
|
|
(120,980
|
)
|
|
(224
|
)
|
|
(135,740
|
)
|
December 31, 2014
|
|
17,687
|
|
|
1,155,028
|
|
|
441
|
|
|
1,263,796
|
|
(1)
|
Total Proved Reserves quantities on a per Mcfe basis are comprised of
91%
natural gas,
8%
oil, and
1%
NGLs. Our future cash inflows from our total Proved Reserves as of December 31, 2014 were comprised of
74%
natural gas and
26%
oil.
|
(2)
|
Revisions of previous estimates include both reserves in place at the beginning of the year, acquisitions and divestitures during the year. There were no reclassifications of Proved Undeveloped Reserves to unproved reserves during 2014 pursuant to the five year development rule established by the SEC.
|
|
Mmcfe
|
|
Proved Undeveloped Reserves at January 1, 2014
|
386,954
|
|
Purchases of Proved Undeveloped Reserves in place
|
—
|
|
Sales of Proved Undeveloped Reserves
|
(4,526
|
)
|
New discoveries and extensions (1)
|
63,018
|
|
Proved Undeveloped Reserves transferred to developed (2)
|
(71,776
|
)
|
Proved Undeveloped Reserves transferred to unproved (3)
|
—
|
|
Other revisions of previous estimates of Proved Undeveloped Reserves (4)
|
298,916
|
|
Proved Undeveloped Reserves at December 31, 2014
|
672,586
|
|
(1)
|
Approximately
64%
,
18%
and
18%
of the discoveries and extensions of Proved Undeveloped Reserves in
2014
occurred in the Haynesville shale, Bossier shale and Eagle Ford shale, respectively. The discoveries and extensions in the Haynesville and Bossier shales were primarily due to our development of the Shelby area of East Texas.
|
(2)
|
Approximately
91%
and
9%
of the Proved Undeveloped Reserves transferred to Proved Developed Reserves were in the Haynesville shale and Eagle Ford shale, respectively. Capital costs incurred to convert Proved Undeveloped Reserves to Proved Developed Reserves were
$132.9 million
.
|
(3)
|
Represents Proved Undeveloped Reserves that were reclassified to unproved pursuant to the five year development rule established by the SEC. We did not reclassify any Proved Undeveloped Reserves to unproved reserves during 2014.
|
(4)
|
The other revisions of previous estimates included upward revisions due to price of 159.8 Bcfe and upward revisions due to performance and other factors of 118.9 Bcfe. The revisions due to price primarily related to increased natural gas prices which resulted in the reclassification of unproved locations to Proved Undeveloped properties that became economical when using the prices prescribed by the SEC. The revisions due to performance and other factors primarily consisted of improved well performance in Haynesville and Bossier shale wells in the Shelby area of East Texas and Marcellus shale wells in the Appalachia region.
|
|
|
Year Ended December 31,
|
||||||||||
(in thousands, except production and per unit amounts)
|
|
2014
|
|
2013
|
|
2012
|
||||||
Revenues, production and prices:
|
|
|
|
|
|
|
||||||
Oil:
|
|
|
|
|
|
|
||||||
Revenue
|
|
$
|
196,316
|
|
|
$
|
111,440
|
|
|
$
|
62,119
|
|
Production sold (Mbbls)
|
|
2,236
|
|
|
1,188
|
|
|
704
|
|
|||
Average sales price per Bbl
|
|
$
|
87.80
|
|
|
$
|
93.80
|
|
|
$
|
88.24
|
|
Natural gas:
|
|
|
|
|
|
|
||||||
Revenue
|
|
$
|
457,946
|
|
|
$
|
514,309
|
|
|
$
|
462,422
|
|
Production sold (Mmcf)
|
|
120,980
|
|
|
153,321
|
|
|
182,644
|
|
|||
Average sales price per Mcf
|
|
$
|
3.79
|
|
|
$
|
3.35
|
|
|
$
|
2.53
|
|
Natural gas liquids:
|
|
|
|
|
|
|
||||||
Revenue
|
|
$
|
6,007
|
|
|
$
|
8,560
|
|
|
$
|
22,068
|
|
Production sold (Mbbls)
|
|
224
|
|
|
243
|
|
|
510
|
|
|||
Average sales price per Bbl
|
|
$
|
26.82
|
|
|
$
|
35.23
|
|
|
$
|
43.27
|
|
Costs and Expenses:
|
|
|
|
|
|
|
||||||
Oil and natural gas operating costs per Mcfe
|
|
$
|
0.47
|
|
|
$
|
0.38
|
|
|
$
|
0.41
|
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
Holly field:
|
|
|
|
|
|
||||||
Natural gas production sold (Mmcf)
|
82,299
|
|
|
107,746
|
|
|
111,629
|
|
|||
Average price per Mcf
|
$
|
4.02
|
|
|
$
|
3.39
|
|
|
$
|
2.47
|
|
Oil and natural gas operating costs per Mcf
|
0.22
|
|
|
0.13
|
|
|
0.11
|
|
|||
Shelby field:
|
|
|
|
|
|
||||||
Natural gas production sold (Mmcf)
|
10,314
|
|
|
12,020
|
|
|
24,764
|
|
|||
Average price per Mcf
|
$
|
3.90
|
|
|
$
|
3.32
|
|
|
$
|
2.48
|
|
Oil and natural gas operating costs per Mcf
|
0.33
|
|
|
0.28
|
|
|
0.17
|
|
|
|
At December 31, 2014
|
||||||||||||||||
|
|
Gross wells (1)
|
|
Net wells
|
||||||||||||||
|
|
Oil
|
|
Natural gas
|
|
Total
|
|
Oil
|
|
Natural gas
|
|
Total
|
||||||
Producing region:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
East Texas/North Louisiana
|
|
—
|
|
|
691
|
|
|
691
|
|
|
—
|
|
|
246.6
|
|
|
246.6
|
|
South Texas
|
|
220
|
|
|
5
|
|
|
225
|
|
|
108.0
|
|
|
2.2
|
|
|
110.2
|
|
Appalachia and other
|
|
338
|
|
|
5,812
|
|
|
6,150
|
|
|
165.2
|
|
|
2,629.9
|
|
|
2,795.1
|
|
Total
|
|
558
|
|
|
6,508
|
|
|
7,066
|
|
|
273.2
|
|
|
2,878.7
|
|
|
3,151.9
|
|
(1)
|
As of
December 31, 2014
, we held interests in
1
gross well with multiple completions.
|
|
|
Development wells
|
||||||||||||||||
|
|
Gross
|
|
Net
|
||||||||||||||
|
|
Productive
|
|
Dry
|
|
Total
|
|
Productive
|
|
Dry
|
|
Total
|
||||||
Year ended December 31, 2014 (1)
|
|
98
|
|
|
—
|
|
|
98
|
|
|
29.6
|
|
|
—
|
|
|
29.6
|
|
Year ended December 31, 2013
|
|
105
|
|
|
2
|
|
|
107
|
|
|
48.7
|
|
|
0.5
|
|
|
49.2
|
|
Year ended December 31, 2012
|
|
169
|
|
|
2
|
|
|
171
|
|
|
73.8
|
|
|
1.9
|
|
|
75.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
|
Exploratory wells
|
||||||||||||||||
|
|
Gross
|
|
Net
|
||||||||||||||
|
|
Productive
|
|
Dry
|
|
Total
|
|
Productive
|
|
Dry
|
|
Total
|
||||||
Year ended December 31, 2014 (1)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Year ended December 31, 2013 (2)
|
|
15
|
|
|
—
|
|
|
15
|
|
|
7.7
|
|
|
—
|
|
|
7.7
|
|
Year ended December 31, 2012 (3)
|
|
6
|
|
|
—
|
|
|
6
|
|
|
2.2
|
|
|
—
|
|
|
2.2
|
|
(1)
|
We did not complete any exploratory wells in 2014, but did initiate the drilling of one exploratory well in the Bossier shale in North Louisiana late in 2014. Our development wells in 2014 included the Haynesville and Bossier shales in DeSoto Parish, Louisiana, and the Shelby area of East Texas. Our development wells also included the Eagle Ford shale in our core area in Zavala County, Texas and certain wells outside our core area as part of a farmout agreement. The wells outside of our core area are considered development wells as a result of a successful drilling program in this area in 2014.
|
(2)
|
Exploratory wells in 2013 included certain wells drilled in the Eagle Ford shale under the farmout agreement outside of our core area in Zavala County, Texas and certain wells in the Marcellus shale in Jefferson, Clarion and Sullivan Counties, Pennsylvania.
|
(3)
|
Exploratory wells in 2012 include certain wells drilled in the Marcellus shale formation in Jefferson and Sullivan Counties, Pennsylvania.
|
|
|
At December 31, 2014
|
||||||||||
|
|
Developed
|
|
Undeveloped
|
||||||||
Area
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||
East Texas/North Louisiana
|
|
149,700
|
|
|
71,700
|
|
|
80,900
|
|
|
27,600
|
|
South Texas
|
|
93,500
|
|
|
48,100
|
|
|
7,900
|
|
|
4,800
|
|
Appalachia
|
|
397,300
|
|
|
181,000
|
|
|
253,500
|
|
|
109,000
|
|
Other
|
|
4,400
|
|
|
3,200
|
|
|
4,200
|
|
|
3,900
|
|
Total
|
|
644,900
|
|
|
304,000
|
|
|
346,500
|
|
|
145,300
|
|
•
|
the location of wells;
|
•
|
the method of drilling, completion and operating wells;
|
•
|
the surface use and restoration of properties upon which wells are drilled;
|
•
|
the plugging and abandoning of wells;
|
•
|
notice to surface owners and other third parties; and
|
•
|
produced water and waste disposal.
|
•
|
the Oil Pollution Act of 1990 (“OPA”);
|
•
|
the Clean Water Act of 1972 (“CWA”);
|
•
|
the Rivers and Harbors Act of 1899;
|
•
|
the Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”);
|
•
|
the Resource Conservation and Recovery Act (“RCRA”);
|
•
|
the Clean Air Act (“CAA”); and
|
•
|
the Safe Drinking Water Act (“SDWA”).
|
•
|
noise control ordinances;
|
•
|
traffic control ordinances;
|
•
|
limitations on the hours of operations; and
|
•
|
mandatory reporting of accidents, spills and pressure test failures.
|
•
|
customary royalty and overriding royalty interests;
|
•
|
liens incident to operating agreements; and
|
•
|
liens for current taxes and other burdens and minor encumbrances, easements and restrictions.
|
•
|
our future financial and operating performance and results;
|
•
|
our business strategy;
|
•
|
market prices;
|
•
|
our future use of derivative financial instruments; and
|
•
|
our plans and forecasts.
|
•
|
fluctuations in the prices of oil, natural gas and natural gas liquids;
|
•
|
the availability of oil, natural gas and natural gas liquids;
|
•
|
future capital requirements and availability of financing;
|
•
|
our ability to meet our current and future debt service obligations, including our ability to maintain compliance with our debt covenants;
|
•
|
disruption of credit and capital markets and the ability of financial institutions to honor their commitments;
|
•
|
estimates of reserves and economic assumptions, including estimates related to acquisitions and dispositions of oil and natural gas properties;
|
•
|
geological concentration of our reserves;
|
•
|
risks associated with drilling and operating wells;
|
•
|
exploratory risks, including those related to our activities in shale formations;
|
•
|
discovery, acquisition, development and replacement of oil and natural gas reserves;
|
•
|
cash flow and liquidity;
|
•
|
timing and amount of future production of oil and natural gas;
|
•
|
availability of drilling and production equipment;
|
•
|
availability of water and other materials for drilling and completion activities;
|
•
|
marketing of oil and natural gas;
|
•
|
political and economic conditions and events in oil-producing and natural gas-producing countries;
|
•
|
title to our properties;
|
•
|
litigation;
|
•
|
competition;
|
•
|
our ability to attract and retain key personnel, including our search for a chief executive officer;
|
•
|
general economic conditions, including costs associated with drilling and operations of our properties;
|
•
|
environmental or other governmental regulations, including legislation to reduce emissions of greenhouse gases, legislation of derivative financial instruments, regulation of hydraulic fracture stimulation and elimination of income tax incentives available to our industry;
|
•
|
receipt and collectability of amounts owed to us by purchasers of our production and counterparties to our derivative financial instruments;
|
•
|
decisions whether or not to enter into derivative financial instruments;
|
•
|
potential acts of terrorism;
|
•
|
our ability to manage joint ventures with third parties, including the resolution of any material disagreements and our partners’ ability to satisfy obligations under these arrangements;
|
•
|
actions of third party co-owners of interests in properties in which we also own an interest;
|
•
|
fluctuations in interest rates; and
|
•
|
our ability to effectively integrate companies and properties that we acquire.
|
Item 1A.
|
Risk Factors
|
•
|
supply and demand for oil and natural gas and expectations regarding supply and demand;
|
•
|
the level of domestic production;
|
•
|
the availability of imported oil and natural gas;
|
•
|
federal regulations generally prohibiting the export of U.S. crude oil;
|
•
|
federal regulations applicable to the export of, and construction of export facilities for natural gas and NGLs.
|
•
|
political and economic conditions and events in foreign oil and natural gas producing nations, including embargoes, continued hostilities in the Middle East and other sustained military campaigns, and acts of terrorism or sabotage;
|
•
|
the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
|
•
|
the cost and availability of transportation and pipeline systems with adequate capacity;
|
•
|
the cost and availability of other competitive fuels;
|
•
|
fluctuating and seasonal demand for oil, natural gas and refined products;
|
•
|
concerns about global warming or other conservation initiatives and the extent of governmental price controls and regulation of production;
|
•
|
regional price differentials and quality differentials of oil and natural gas;
|
•
|
the availability of refining capacity;
|
•
|
technological advances affecting oil and natural gas production and consumption;
|
•
|
weather conditions and natural disasters;
|
•
|
foreign and domestic government relations; and
|
•
|
overall economic conditions.
|
•
|
our joint venture partners may share certain approval rights over major decisions;
|
•
|
the possibility that our joint venture partners might become insolvent or bankrupt, leaving us liable for their shares of joint venture liabilities;
|
•
|
the possibility that we may incur liabilities as a result of an action taken by our joint venture partners;
|
•
|
joint venture partners may be in a position to take action contrary to our instructions or requests or contrary to our policies or objectives;
|
•
|
disputes between us and our joint venture partners may result in litigation or arbitration that would increase our expenses, delay or terminate projects and prevent our officers and directors from focusing their time and effort on our business;
|
•
|
that under certain joint venture arrangements, neither joint venture partner may have the power to control the venture, and an impasse could be reached which might have a negative influence on our investment in the joint venture; and
|
•
|
our joint venture partners may decide to terminate their relationship with us in any joint venture company or sell their interest in any of these companies and we may be unable to replace such joint venture partner or raise the necessary financing to purchase such joint venture partner’s interest.
|
•
|
operating a significantly larger combined organization and adding operations;
|
•
|
difficulties in the assimilation of the assets and operations of the acquired business, especially if the assets acquired are in a new business segment or geographic area;
|
•
|
the risk that oil and natural gas reserves acquired may not be of the anticipated magnitude or may not be developed as anticipated;
|
•
|
the loss of significant key employees from the acquired business;
|
•
|
the diversion of management’s attention from other business concerns;
|
•
|
the failure to realize expected profitability or growth;
|
•
|
the failure to realize expected synergies and cost savings;
|
•
|
coordinating geographically disparate organizations, systems and facilities; and
|
•
|
coordinating or consolidating corporate and administrative functions.
|
•
|
fires, explosions and blowouts;
|
•
|
pipe failures;
|
•
|
abnormally pressured formations; and
|
•
|
environmental accidents such as oil spills, natural gas leaks, ruptures or discharges of toxic gases, brine or well fluids into the environment (including groundwater contamination).
|
•
|
injury or loss of life;
|
•
|
severe damage to or destruction of property, natural resources and equipment;
|
•
|
pollution or other environmental damage;
|
•
|
environmental clean-up responsibilities;
|
•
|
regulatory investigation;
|
•
|
penalties and suspension of operations; or
|
•
|
attorneys’ fees and other expenses incurred in the prosecution or defense of litigation.
|
•
|
market prices may exceed the prices which we are contracted to receive, resulting in our need to make significant cash payments;
|
•
|
there may be a change in the expected differential between the underlying price in the derivative financial instrument agreement and actual prices received; or
|
•
|
the counterparty to the derivative financial instrument contract may default on its contractual obligations to us.
|
•
|
it may be more difficult for us to satisfy our obligations with respect to our indebtedness, and any failure to comply with the obligations of any of our debt agreements, including financial and other restrictive covenants, could result in an event of default under the EXCO Resources Credit Agreement or the indenture governing the 2018 Notes and 2022 Notes ("Indenture"), and the agreements governing our other indebtedness;
|
•
|
we may have difficulty borrowing money in the future for acquisitions (including obligations to acquire interests in wells pursuant to the Participation Agreement with KKR), capital expenditures or to meet our operating expenses or other general corporate obligations;
|
•
|
the amount of our interest expense may increase because certain of our borrowings are at variable rates of interest;
|
•
|
we will need to use a substantial portion of our cash flows to pay principal and interest on our debt, which will reduce the amount of money we have for operations, working capital, capital expenditures, expansion, acquisitions or general corporate or other business activities;
|
•
|
we may have a higher level of debt than some of our competitors, which may put us at a competitive disadvantage;
|
•
|
we may be more vulnerable to economic downturns and adverse developments in our industry or the economy in general, especially declines in oil and natural gas prices;
|
•
|
when oil and natural gas prices decline, our ability to maintain compliance with our financial covenants becomes more difficult and our borrowing base is subject to reductions, which may reduce or eliminate our ability to fund our operations; and
|
•
|
our debt level could limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate.
|
•
|
dispose of assets;
|
•
|
incur or guarantee additional indebtedness and issue certain types of preferred shares;
|
•
|
pay dividends on our capital stock;
|
•
|
create liens on our assets;
|
•
|
enter into sale or leaseback transactions;
|
•
|
enter into specified investments or acquisitions;
|
•
|
repurchase, redeem or retire our capital stock or subordinated debt;
|
•
|
merge or consolidate, or transfer all or substantially all of our assets and the assets of our subsidiaries;
|
•
|
engage in specified transactions with subsidiaries and affiliates; or
|
•
|
pursue other corporate activities.
|
•
|
limited in how we conduct our business;
|
•
|
unable to raise additional debt or equity financing during general economic, business or industry downturns; or
|
•
|
unable to compete effectively or to take advantage of new business opportunities.
|
•
|
announcements relating to our business or the business of our competitors;
|
•
|
changes in expectations as to our future financial performance or changes in financial estimates of public market analysis;
|
•
|
actual or anticipated quarterly variations in our operating results;
|
•
|
conditions generally affecting the oil and natural gas industry;
|
•
|
the success of our operating strategy; and
|
•
|
the operating and share price performance of other comparable companies.
|
•
|
any merger, consolidation or sale of all or substantially all of our assets;
|
•
|
the election of members of our board of directors; and
|
•
|
any amendment to our articles of incorporation.
|
Item 1B.
|
Unresolved Staff Comments
|
Location
|
|
Approximate square footage
|
|
Approximate monthly payment
|
|
Expiration
|
|||
Dallas, Texas (1)
|
|
155,000
|
|
|
$
|
253,826
|
|
|
May 31, 2025
|
Cranberry Township, Pennsylvania
|
|
15,400
|
|
|
$
|
22,500
|
|
|
December 31, 2017
|
(1)
|
The office lease in Dallas, Texas contains a right on our behalf to terminate the lease agreement early on June 30, 2020 or June 30, 2022.
|
Item 5.
|
Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
|
Period
|
|
Total Number of Shares Purchased (1)
|
|
Average Price Paid Per Share
|
|
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
|
|
Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (in millions) (2)
|
||||||
October 1 - October 31
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
192.5
|
|
November 1 - November 30
|
|
32,011
|
|
|
3.78
|
|
|
—
|
|
|
192.5
|
|
||
December 1 - December 31
|
|
6,810
|
|
|
2.24
|
|
|
—
|
|
|
192.5
|
|
||
Total
|
|
38,821
|
|
|
3.51
|
|
|
—
|
|
|
|
(2)
|
On July 19, 2010, we announced a $200.0 million share repurchase program.
|
Item 6.
|
Selected Financial Data
|
|
|
Year Ended December 31,
|
||||||||||||||||||
(in thousands, except per share amounts)
|
|
2014
|
|
2013
|
|
2012
|
|
2011
|
|
2010
|
||||||||||
Statement of operations data (1):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil and natural gas
|
|
$
|
660,269
|
|
|
$
|
634,309
|
|
|
$
|
546,609
|
|
|
$
|
754,201
|
|
|
$
|
515,226
|
|
Cost and expenses:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil and natural gas production (2)
|
|
94,326
|
|
|
83,248
|
|
|
104,610
|
|
|
108,641
|
|
|
108,184
|
|
|||||
Gathering and transportation
|
|
101,574
|
|
|
100,645
|
|
|
102,875
|
|
|
86,881
|
|
|
54,877
|
|
|||||
Depletion, depreciation and amortization
|
|
263,569
|
|
|
245,775
|
|
|
303,156
|
|
|
362,956
|
|
|
196,963
|
|
|||||
Impairment of oil and natural gas properties
|
|
—
|
|
|
108,546
|
|
|
1,346,749
|
|
|
233,239
|
|
|
—
|
|
|||||
Accretion of discount on asset retirement obligations
|
|
2,690
|
|
|
2,514
|
|
|
3,887
|
|
|
3,652
|
|
|
3,758
|
|
|||||
General and administrative (3)
|
|
65,920
|
|
|
91,878
|
|
|
83,818
|
|
|
104,618
|
|
|
105,114
|
|
|||||
(Gain) loss on divestitures and other operating items (4)
|
|
5,315
|
|
|
(177,518
|
)
|
|
17,029
|
|
|
23,819
|
|
|
(509,872
|
)
|
|||||
Total cost and expenses
|
|
533,394
|
|
|
455,088
|
|
|
1,962,124
|
|
|
923,806
|
|
|
(40,976
|
)
|
|||||
Operating income (loss)
|
|
126,875
|
|
|
179,221
|
|
|
(1,415,515
|
)
|
|
(169,605
|
)
|
|
556,202
|
|
|||||
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest expense, net
|
|
(94,284
|
)
|
|
(102,589
|
)
|
|
(73,492
|
)
|
|
(61,023
|
)
|
|
(45,533
|
)
|
|||||
Gain (loss) on derivative financial instruments (5)
|
|
87,665
|
|
|
(320
|
)
|
|
66,133
|
|
|
219,730
|
|
|
146,516
|
|
|||||
Other income (expense)
|
|
241
|
|
|
(828
|
)
|
|
969
|
|
|
788
|
|
|
327
|
|
|||||
Equity income (loss) (6)
|
|
172
|
|
|
(53,280
|
)
|
|
28,620
|
|
|
32,706
|
|
|
16,022
|
|
|||||
Total other income (expense)
|
|
(6,206
|
)
|
|
(157,017
|
)
|
|
22,230
|
|
|
192,201
|
|
|
117,332
|
|
|||||
Income (loss) before income taxes
|
|
120,669
|
|
|
22,204
|
|
|
(1,393,285
|
)
|
|
22,596
|
|
|
673,534
|
|
|||||
Income tax expense
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,608
|
|
|||||
Net income (loss)
|
|
$
|
120,669
|
|
|
$
|
22,204
|
|
|
$
|
(1,393,285
|
)
|
|
$
|
22,596
|
|
|
$
|
671,926
|
|
Basic net income (loss) per share
|
|
$
|
0.45
|
|
|
$
|
0.10
|
|
|
$
|
(6.50
|
)
|
|
$
|
0.11
|
|
|
$
|
3.16
|
|
Diluted net income (loss) per share
|
|
$
|
0.45
|
|
|
$
|
0.10
|
|
|
$
|
(6.50
|
)
|
|
$
|
0.10
|
|
|
$
|
3.11
|
|
Cash dividends declared per share
|
|
$
|
0.15
|
|
|
$
|
0.20
|
|
|
$
|
0.16
|
|
|
$
|
0.16
|
|
|
$
|
0.14
|
|
Weighted average common shares and common share equivalents outstanding:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
|
268,258
|
|
|
215,011
|
|
|
214,321
|
|
|
213,908
|
|
|
212,465
|
|
|||||
Diluted
|
|
268,376
|
|
|
230,912
|
|
|
214,321
|
|
|
216,705
|
|
|
215,735
|
|
|||||
Statement of cash flow data:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating activities
|
|
$
|
362,093
|
|
|
$
|
350,634
|
|
|
$
|
514,786
|
|
|
$
|
428,543
|
|
|
$
|
339,921
|
|
Investing activities
|
|
(221,588
|
)
|
|
(252,478
|
)
|
|
(427,094
|
)
|
|
(709,531
|
)
|
|
(712,854
|
)
|
|||||
Financing activities
|
|
(144,683
|
)
|
|
(93,317
|
)
|
|
(74,045
|
)
|
|
268,756
|
|
|
348,755
|
|
|||||
Balance sheet data:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Current assets
|
|
$
|
330,766
|
|
|
$
|
305,854
|
|
|
$
|
361,866
|
|
|
$
|
678,008
|
|
|
$
|
520,460
|
|
Total assets
|
|
2,356,896
|
|
|
2,408,628
|
|
|
2,323,732
|
|
|
3,791,587
|
|
|
3,477,420
|
|
|||||
Current liabilities
|
|
365,371
|
|
|
349,170
|
|
|
237,931
|
|
|
287,399
|
|
|
285,698
|
|
|||||
Long-term debt
|
|
1,446,535
|
|
|
1,858,912
|
|
|
1,848,972
|
|
|
1,887,828
|
|
|
1,588,269
|
|
|||||
Shareholders' equity
|
|
510,004
|
|
|
147,905
|
|
|
149,393
|
|
|
1,558,332
|
|
|
1,540,552
|
|
|||||
Total liabilities and shareholders' equity
|
|
2,356,896
|
|
|
2,408,628
|
|
|
2,323,732
|
|
|
3,791,587
|
|
|
3,477,420
|
|
(1)
|
We have completed numerous acquisitions and dispositions which impact the comparability of the selected financial data between periods.
|
(2)
|
Share-based compensation calculated pursuant to FASB Accounting Standards Codification 718,
Compensation-Stock Compensation
("ASC 718") included in oil and natural gas production costs was
$0.1 million
and
$1.0 million
for the years ended December 31, 2011 and 2010, respectively. We had no share-based compensation included in oil and natural gas production costs for the years ended December 31, 2014, 2013 and 2012.
|
(3)
|
Share-based compensation calculated pursuant to ASC 718 included in general and administrative expenses was
$5.0 million
,
$10.7 million
,
$8.9 million
,
$10.9 million
and
$15.8 million
for the years ended
December 31, 2014
, 2013, 2012, 2011 and 2010, respectively.
|
(4)
|
During 2013, we recognized a gain on the contribution of properties to Compass. During 2010, we recognized gains on the sale transactions attributable to the formation of our joint ventures with BG Group.
|
(5)
|
We do not designate our derivative financial instruments as hedges and, as a result, the changes in the fair value of our derivative financial instruments are recognized in our Consolidated Statements of Operations. See "Note 2. Summary of significant accounting policies" in the Notes to our Consolidated Financial Statements for a description of this accounting method.
|
(6)
|
On November 15, 2013, we sold our equity interest in TGGT to Azure in exchange for cash proceeds and an equity interest in Azure. We report our equity interest acquired in Azure using the cost method of accounting.
|
Item 7.
|
Management’s Discussion and Analysis of Financial Condition and Results of Operations
|
•
|
the quality and quantity of available data;
|
•
|
the interpretation of this data;
|
•
|
the accuracy of various mandated economic assumptions; and
|
•
|
the technical qualifications, experience and judgment of the persons preparing the estimates.
|
(1)
|
Mmcfe is calculated by converting one barrel of oil or NGLs into six Mcf of natural gas.
|
(2)
|
Share-based compensation expense included in general and administrative expenses was
$5.0 million
,
$10.7 million
and
$8.9 million
for the years ended
December 31, 2014
,
2013
and
2012
, respectively.
|
•
|
the acquisitions of the Haynesville and Eagle Ford assets during 2013;
|
•
|
the formation and subsequent sale of Compass during 2013 and 2014, respectively;
|
•
|
the sale of our equity interest in TGGT Holdings, LLC ("TGGT") during 2013;
|
•
|
fluctuations in oil, natural gas and NGL prices, which impact our oil and natural gas reserves, revenues, cash flows and net income or loss;
|
•
|
impairments of our oil and natural gas properties in 2013 and 2012;
|
•
|
asset impairments and other non-recurring costs;
|
•
|
mark-to-market gains and losses from our derivative financial instruments;
|
•
|
changes in Proved Reserves and production volumes and their impact on depletion;
|
•
|
the impact of declining natural gas production volumes from our reduced horizontal drilling activities in certain shale formations; and
|
•
|
significant changes in our capital structure as a result of the Rights Offering and debt financing transactions.
|
•
|
supply and demand for oil and natural gas and expectations regarding supply and demand;
|
•
|
the level of domestic production;
|
•
|
the availability of imported oil and natural gas;
|
•
|
federal regulations generally prohibiting the export of U.S. crude oils;
|
•
|
federal regulations applicable to the export of, and construction of export facilities for natural gas and NGLs.
|
•
|
political and economic conditions and events in foreign oil and natural gas producing nations, including embargoes, continued hostilities in the Middle East and other sustained military campaigns, and acts of terrorism or sabotage;
|
•
|
the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
|
•
|
the cost and availability of transportation and pipeline systems with adequate capacity;
|
•
|
the cost and availability of other competitive fuels;
|
•
|
fluctuating and seasonal demand for oil, natural gas and refined products;
|
•
|
concerns about global warming or other conservation initiatives and the extent of governmental price controls and regulation of production;
|
•
|
regional price differentials and quality differentials of oil and natural gas;
|
•
|
the availability of refining capacity;
|
•
|
technological advances affecting oil and natural gas production and consumption;
|
•
|
weather conditions and natural disasters;
|
•
|
foreign and domestic government relations; and
|
•
|
overall economic conditions.
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
|||||||||||||||||||||||||
|
|
2014
|
|
2013
|
|
Year to year change
|
|||||||||||||||||||||||||||
(dollars in thousands, except per unit rate)
|
|
Production (Mmcfe)
|
|
Revenue
|
|
$/Mcfe
|
|
Production (Mmcfe)
|
|
Revenue
|
|
$/Mcfe
|
|
Production (Mmcfe)
|
|
Revenue
|
|
$/Mcfe
|
|||||||||||||||
Producing region:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
East Texas/North Louisiana
|
|
92,916
|
|
|
$
|
371,074
|
|
|
$
|
3.99
|
|
|
123,218
|
|
|
$
|
417,811
|
|
|
$
|
3.39
|
|
|
(30,302
|
)
|
|
$
|
(46,737
|
)
|
|
$
|
0.60
|
|
South Texas
|
|
13,713
|
|
|
176,022
|
|
|
12.84
|
|
|
6,197
|
|
|
85,926
|
|
|
13.87
|
|
|
7,516
|
|
|
90,096
|
|
|
(1.03
|
)
|
||||||
Appalachia
|
|
21,289
|
|
|
67,794
|
|
|
3.18
|
|
|
22,816
|
|
|
78,424
|
|
|
3.44
|
|
|
(1,527
|
)
|
|
(10,630
|
)
|
|
(0.26
|
)
|
||||||
Other
|
|
364
|
|
|
3,649
|
|
|
10.02
|
|
|
1,139
|
|
|
9,135
|
|
|
8.02
|
|
|
(775
|
)
|
|
(5,486
|
)
|
|
2.00
|
|
||||||
Compass
|
|
7,458
|
|
|
41,730
|
|
|
5.60
|
|
|
8,537
|
|
|
43,013
|
|
|
5.04
|
|
|
(1,079
|
)
|
|
(1,283
|
)
|
|
0.56
|
|
||||||
Total
|
|
135,740
|
|
|
$
|
660,269
|
|
|
$
|
4.86
|
|
|
161,907
|
|
|
$
|
634,309
|
|
|
$
|
3.92
|
|
|
(26,167
|
)
|
|
$
|
25,960
|
|
|
$
|
0.94
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
|||||||||||||||||||||||||
|
|
2013
|
|
2012
|
|
Year to year change
|
|||||||||||||||||||||||||||
(dollars in thousands, except per unit rate)
|
|
Production (Mmcfe)
|
|
Revenue
|
|
$/Mcfe
|
|
Production (Mmcfe)
|
|
Revenue
|
|
$/Mcfe
|
|
Production (Mmcfe)
|
|
Revenue
|
|
$/Mcfe
|
|||||||||||||||
Producing region:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
East Texas/North Louisiana
|
|
123,218
|
|
|
$
|
417,811
|
|
|
$
|
3.39
|
|
|
164,779
|
|
|
$
|
420,579
|
|
|
$
|
2.55
|
|
|
(41,561
|
)
|
|
$
|
(2,768
|
)
|
|
$
|
0.84
|
|
South Texas
|
|
6,197
|
|
|
85,926
|
|
|
13.87
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6,197
|
|
|
85,926
|
|
|
13.87
|
|
||||||
Appalachia
|
|
22,816
|
|
|
78,424
|
|
|
3.44
|
|
|
16,153
|
|
|
47,379
|
|
|
2.93
|
|
|
6,663
|
|
|
31,045
|
|
|
0.51
|
|
||||||
Other
|
|
1,139
|
|
|
9,135
|
|
|
8.02
|
|
|
8,996
|
|
|
78,651
|
|
|
8.74
|
|
|
(7,857
|
)
|
|
(69,516
|
)
|
|
(0.72
|
)
|
||||||
Compass
|
|
8,537
|
|
|
43,013
|
|
|
5.04
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8,537
|
|
|
43,013
|
|
|
5.04
|
|
||||||
Total
|
|
161,907
|
|
|
$
|
634,309
|
|
|
$
|
3.92
|
|
|
189,928
|
|
|
$
|
546,609
|
|
|
$
|
2.88
|
|
|
(28,021
|
)
|
|
$
|
87,700
|
|
|
$
|
1.04
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
||||||||||||||||||||||||||||
|
|
2014
|
|
2013
|
|
Year to year change
|
||||||||||||||||||||||||||||||
(in thousands)
|
|
Lease operating expenses
|
|
Workovers and other
|
|
Total
|
|
Lease operating expenses
|
|
Workovers and other
|
|
Total
|
|
Lease operating expenses
|
|
Workovers and other
|
|
Total
|
||||||||||||||||||
Producing region:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||
East Texas/North Louisiana
|
|
$
|
18,056
|
|
|
$
|
3,815
|
|
|
$
|
21,871
|
|
|
$
|
16,980
|
|
|
$
|
4,294
|
|
|
$
|
21,274
|
|
|
$
|
1,076
|
|
|
$
|
(479
|
)
|
|
$
|
597
|
|
South Texas
|
|
15,242
|
|
|
396
|
|
|
15,638
|
|
|
11,454
|
|
|
13
|
|
|
11,467
|
|
|
3,788
|
|
|
383
|
|
|
4,171
|
|
|||||||||
Appalachia
|
|
14,072
|
|
|
58
|
|
|
14,130
|
|
|
14,073
|
|
|
—
|
|
|
14,073
|
|
|
(1
|
)
|
|
58
|
|
|
57
|
|
|||||||||
Other
|
|
300
|
|
|
—
|
|
|
300
|
|
|
1,623
|
|
|
—
|
|
|
1,623
|
|
|
(1,323
|
)
|
|
—
|
|
|
(1,323
|
)
|
|||||||||
Compass
|
|
10,838
|
|
|
1,690
|
|
|
12,528
|
|
|
11,397
|
|
|
1,443
|
|
|
12,840
|
|
|
(559
|
)
|
|
247
|
|
|
(312
|
)
|
|||||||||
Total
|
|
$
|
58,508
|
|
|
$
|
5,959
|
|
|
$
|
64,467
|
|
|
$
|
55,527
|
|
|
$
|
5,750
|
|
|
$
|
61,277
|
|
|
$
|
2,981
|
|
|
$
|
209
|
|
|
$
|
3,190
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||
|
|
Year Ended December 31,
|
|
|
|
|
|
|
||||||||||||||||||||||||||||
|
|
2014
|
|
2013
|
|
Year to year change
|
||||||||||||||||||||||||||||||
(per Mcfe)
|
|
Lease operating expenses
|
|
Workovers and other
|
|
Total
|
|
Lease operating expenses
|
|
Workovers and other
|
|
Total
|
|
Lease operating expenses
|
|
Workovers and other
|
|
Total
|
||||||||||||||||||
Producing region:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||
East Texas/North Louisiana
|
|
$
|
0.19
|
|
|
$
|
0.04
|
|
|
$
|
0.23
|
|
|
$
|
0.14
|
|
|
$
|
0.03
|
|
|
$
|
0.17
|
|
|
$
|
0.05
|
|
|
$
|
0.01
|
|
|
$
|
0.06
|
|
South Texas
|
|
1.11
|
|
|
0.03
|
|
|
1.14
|
|
|
1.85
|
|
|
—
|
|
|
1.85
|
|
|
(0.74
|
)
|
|
0.03
|
|
|
(0.71
|
)
|
|||||||||
Appalachia
|
|
0.66
|
|
|
—
|
|
|
0.66
|
|
|
0.62
|
|
|
—
|
|
|
0.62
|
|
|
0.04
|
|
|
—
|
|
|
0.04
|
|
|||||||||
Other
|
|
0.82
|
|
|
—
|
|
|
0.82
|
|
|
1.42
|
|
|
—
|
|
|
1.42
|
|
|
(0.60
|
)
|
|
—
|
|
|
(0.60
|
)
|
|||||||||
Compass
|
|
1.45
|
|
|
0.23
|
|
|
1.68
|
|
|
1.34
|
|
|
0.17
|
|
|
1.51
|
|
|
0.11
|
|
|
0.06
|
|
|
0.17
|
|
|||||||||
Total
|
|
$
|
0.43
|
|
|
$
|
0.04
|
|
|
$
|
0.47
|
|
|
$
|
0.34
|
|
|
$
|
0.04
|
|
|
$
|
0.38
|
|
|
$
|
0.09
|
|
|
$
|
—
|
|
|
$
|
0.09
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
||||||||||||||||||||||||||||
|
|
2013
|
|
2012
|
|
Year to year change
|
||||||||||||||||||||||||||||||
(in thousands)
|
|
Lease operating expenses
|
|
Workovers and other
|
|
Total
|
|
Lease operating expenses
|
|
Workovers and other
|
|
Total
|
|
Lease operating expenses
|
|
Workovers and other
|
|
Total
|
||||||||||||||||||
Producing region:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||
East Texas/North Louisiana
|
|
$
|
16,980
|
|
|
$
|
4,294
|
|
|
$
|
21,274
|
|
|
$
|
39,897
|
|
|
$
|
9,497
|
|
|
$
|
49,394
|
|
|
$
|
(22,917
|
)
|
|
$
|
(5,203
|
)
|
|
$
|
(28,120
|
)
|
South Texas
|
|
11,454
|
|
|
13
|
|
|
11,467
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
11,454
|
|
|
13
|
|
|
11,467
|
|
|||||||||
Appalachia
|
|
14,073
|
|
|
—
|
|
|
14,073
|
|
|
14,882
|
|
|
—
|
|
|
14,882
|
|
|
(809
|
)
|
|
—
|
|
|
(809
|
)
|
|||||||||
Other
|
|
1,623
|
|
|
—
|
|
|
1,623
|
|
|
12,539
|
|
|
312
|
|
|
12,851
|
|
|
(10,916
|
)
|
|
(312
|
)
|
|
(11,228
|
)
|
|||||||||
Compass
|
|
11,397
|
|
|
1,443
|
|
|
12,840
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
11,397
|
|
|
1,443
|
|
|
12,840
|
|
|||||||||
Total
|
|
$
|
55,527
|
|
|
$
|
5,750
|
|
|
$
|
61,277
|
|
|
$
|
67,318
|
|
|
$
|
9,809
|
|
|
$
|
77,127
|
|
|
$
|
(11,791
|
)
|
|
$
|
(4,059
|
)
|
|
$
|
(15,850
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||
|
|
Year Ended December 31,
|
|
|
|
|
|
|
||||||||||||||||||||||||||||
|
|
2013
|
|
2012
|
|
Year to year change
|
||||||||||||||||||||||||||||||
(per Mcfe)
|
|
Lease operating expenses
|
|
Workovers and other
|
|
Total
|
|
Lease operating expenses
|
|
Workovers and other
|
|
Total
|
|
Lease operating expenses
|
|
Workovers and other
|
|
Total
|
||||||||||||||||||
Producing region:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||
East Texas/North Louisiana
|
|
$
|
0.14
|
|
|
$
|
0.03
|
|
|
$
|
0.17
|
|
|
$
|
0.24
|
|
|
$
|
0.06
|
|
|
$
|
0.30
|
|
|
$
|
(0.10
|
)
|
|
$
|
(0.03
|
)
|
|
$
|
(0.13
|
)
|
South Texas
|
|
1.85
|
|
|
—
|
|
|
1.85
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1.85
|
|
|
—
|
|
|
1.85
|
|
|||||||||
Appalachia
|
|
0.62
|
|
|
—
|
|
|
0.62
|
|
|
0.92
|
|
|
—
|
|
|
0.92
|
|
|
(0.30
|
)
|
|
—
|
|
|
(0.30
|
)
|
|||||||||
Other
|
|
1.42
|
|
|
—
|
|
|
1.42
|
|
|
1.39
|
|
|
0.03
|
|
|
1.42
|
|
|
0.03
|
|
|
(0.03
|
)
|
|
—
|
|
|||||||||
Compass
|
|
1.34
|
|
|
0.17
|
|
|
1.51
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1.34
|
|
|
0.17
|
|
|
1.51
|
|
|||||||||
Total
|
|
$
|
0.34
|
|
|
$
|
0.04
|
|
|
$
|
0.38
|
|
|
$
|
0.36
|
|
|
$
|
0.05
|
|
|
$
|
0.41
|
|
|
$
|
(0.02
|
)
|
|
$
|
(0.01
|
)
|
|
$
|
(0.03
|
)
|
|
|
Year Ended December 31,
|
|||||||||||||||||||||||||||||||
|
|
2014
|
|
2013
|
|
2012
|
|||||||||||||||||||||||||||
(in thousands, except per unit rate)
|
|
Production and ad valorem taxes
|
|
% of revenue
|
|
Taxes $/Mcfe
|
|
Production and ad valorem taxes
|
|
% of revenue
|
|
Taxes $/Mcfe
|
|
Production and ad valorem taxes
|
|
% of revenue
|
|
Taxes $/Mcfe
|
|||||||||||||||
Producing region:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
East Texas/North Louisiana
|
|
$
|
10,032
|
|
|
2.7
|
%
|
|
$
|
0.11
|
|
|
$
|
9,287
|
|
|
2.2
|
%
|
|
$
|
0.08
|
|
|
$
|
17,501
|
|
|
4.2
|
%
|
|
$
|
0.11
|
|
South Texas
|
|
13,406
|
|
|
7.6
|
%
|
|
0.98
|
|
|
4,962
|
|
|
5.8
|
%
|
|
0.80
|
|
|
—
|
|
|
—
|
%
|
|
—
|
|
||||||
Appalachia
|
|
2,256
|
|
|
3.3
|
%
|
|
0.11
|
|
|
2,653
|
|
|
3.4
|
%
|
|
0.12
|
|
|
3,013
|
|
|
6.4
|
%
|
|
0.19
|
|
||||||
Other
|
|
92
|
|
|
2.5
|
%
|
|
0.25
|
|
|
815
|
|
|
8.9
|
%
|
|
0.72
|
|
|
6,969
|
|
|
8.9
|
%
|
|
0.77
|
|
||||||
Compass
|
|
4,073
|
|
|
9.8
|
%
|
|
0.55
|
|
|
4,254
|
|
|
9.9
|
%
|
|
0.50
|
|
|
—
|
|
|
—
|
%
|
|
—
|
|
||||||
Total
|
|
$
|
29,859
|
|
|
4.5
|
%
|
|
$
|
0.22
|
|
|
$
|
21,971
|
|
|
3.5
|
%
|
|
$
|
0.14
|
|
|
$
|
27,483
|
|
|
5.0
|
%
|
|
$
|
0.14
|
|
|
|
Year Ended December 31,
|
|
Year to year change
|
||||||||||||||||
(in thousands, except per unit rate)
|
|
2014
|
|
2013
|
|
2012
|
|
2014-2013
|
|
2013-2012
|
||||||||||
General and administrative costs:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Gross general and administrative expense
|
|
$
|
119,959
|
|
|
$
|
147,432
|
|
|
$
|
152,057
|
|
|
$
|
(27,473
|
)
|
|
$
|
(4,625
|
)
|
Technical services and service agreement charges
|
|
(24,747
|
)
|
|
(26,846
|
)
|
|
(25,242
|
)
|
|
2,099
|
|
|
(1,604
|
)
|
|||||
Operator overhead reimbursements
|
|
(13,507
|
)
|
|
(10,462
|
)
|
|
(20,544
|
)
|
|
(3,045
|
)
|
|
10,082
|
|
|||||
Capitalized salaries and share-based compensation
|
|
(15,785
|
)
|
|
(18,246
|
)
|
|
(22,453
|
)
|
|
2,461
|
|
|
4,207
|
|
|||||
General and administrative expense
|
|
$
|
65,920
|
|
|
$
|
91,878
|
|
|
$
|
83,818
|
|
|
$
|
(25,958
|
)
|
|
$
|
8,060
|
|
•
|
decreased personnel and employee relocation costs of
$12.4 million
. The decrease was primarily the result of a reduction in our workforce and the centralization of certain functions from the Appalachia region. Also, we incurred$5.0 million of severance costs during 2013 associated with the resignation of our former chairman and chief executive officer. The decrease was partially offset by
$2.2 million
in severance costs associated with the reduction in our workforce during the second quarter of 2014;
|
•
|
decreased gross share-based compensation expense of
$7.6 million
. The decrease was primarily due to a reduction in headcount, higher forfeitures and additional expenses incurred with the modification of share-based payments in connection with the retirement and resignation of former executives in the prior year;
|
•
|
decreased various other gross general and administrative expenses of
$7.5 million
. The decrease reflects our efforts to reduce our general and administrative costs such as office expenses, travel and software licenses. We also incurred additional costs for legal and transition services related to the Haynesville and Eagle Ford asset acquisitions in 2013;
|
•
|
decreased technical services and service agreement recoveries of
$2.1 million
. The decrease was primarily a result of reduced headcount and increased focus on the development of assets that are not included in joint venture arrangements in which we can recover technical services including our operations in the South Texas region;
|
•
|
increased operator overhead reimbursements of
$3.0 million
. The increase is primarily associated with the additional operated wells acquired and developed in the Haynesville and Eagle Ford shales; and
|
•
|
decreased capitalized salaries and share-based compensation expense of $2.5 million primarily as a result of a reduction in employee headcount.
|
•
|
decreased personnel expenses of $11.0 million primarily related to a reduction in employee headcount. This decrease was partially offset by $5.0 million of severance costs during 2013 associated with the resignation of our former chairman and chief executive officer. The decrease also included a reduction in contract labor costs as part of cost-cutting initiatives throughout the Company;
|
•
|
increased technical service and service agreement recoveries of $1.6 million primarily due to service agreement charges associated with the operations of Compass, which was partially offset by decreased employee costs;
|
•
|
decreased overhead recoveries of $10.1 million arising from reductions in our drilling program and the contribution of properties to Compass;
|
•
|
decreased capitalized salaries and share-based compensation expense of $4.2 million primarily as a result of a reduction in employee headcount;
|
•
|
increased share-based compensation expense of $1.6 million primarily associated with the modification of share-based payments in connection with the retirement and resignation of former executives in the prior year. This was partially offset by a reduction in employee headcount from prior year; and
|
•
|
increased various other expenses of $4.8 million primarily consisting of employee relocation costs associated with the centralization of certain functions from the Appalachia region, transition service costs associated with the acquisition of Haynesville and Eagle Ford assets, as well as higher engineering and technology costs.
|
|
|
Year Ended December 31,
|
|
Period to period change
|
||||||||||||||||
(in thousands)
|
|
2014
|
|
2013
|
|
2012
|
|
2014-2013
|
|
2013-2012
|
||||||||||
Interest expense:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
2018 Notes
|
|
$
|
57,585
|
|
|
$
|
57,485
|
|
|
$
|
57,394
|
|
|
$
|
100
|
|
|
$
|
91
|
|
2022 Notes
|
|
30,104
|
|
|
—
|
|
|
—
|
|
|
30,104
|
|
|
—
|
|
|||||
EXCO Resources Credit Agreement
|
|
16,368
|
|
|
33,119
|
|
|
31,068
|
|
|
(16,751
|
)
|
|
2,051
|
|
|||||
Compass Production Partners Credit Agreement
|
|
2,022
|
|
|
2,335
|
|
|
—
|
|
|
(313
|
)
|
|
2,335
|
|
|||||
Amortization of deferred financing costs
|
|
7,939
|
|
|
28,169
|
|
|
8,644
|
|
|
(20,230
|
)
|
|
19,525
|
|
|||||
Capitalized interest
|
|
(20,060
|
)
|
|
(18,729
|
)
|
|
(23,809
|
)
|
|
(1,331
|
)
|
|
5,080
|
|
|||||
Other
|
|
326
|
|
|
210
|
|
|
195
|
|
|
116
|
|
|
15
|
|
|||||
Total interest expense
|
|
$
|
94,284
|
|
|
$
|
102,589
|
|
|
$
|
73,492
|
|
|
$
|
(8,305
|
)
|
|
$
|
29,097
|
|
|
|
Year Ended December 31,
|
|
Period to period change
|
||||||||||||||||
Average realized pricing:
|
|
2014
|
|
2013
|
|
2012
|
|
2014-2013
|
|
2013-2012
|
||||||||||
Natural gas equivalent per Mcfe
|
|
$
|
4.86
|
|
|
$
|
3.92
|
|
|
$
|
2.88
|
|
|
$
|
0.94
|
|
|
$
|
1.04
|
|
Cash settlements (payments) on derivative financial instruments, per Mcfe
|
|
(0.14
|
)
|
|
0.26
|
|
|
1.06
|
|
|
(0.40
|
)
|
|
(0.80
|
)
|
|||||
Net price per Mcfe, including derivative financial instruments
|
|
$
|
4.72
|
|
|
$
|
4.18
|
|
|
$
|
3.94
|
|
|
$
|
0.54
|
|
|
$
|
0.24
|
|
|
|
Year Ended December 31,
|
||||||||||
(in thousands)
|
|
2014
|
|
2013
|
|
2012
|
||||||
Federal income taxes (benefit) provision at statutory rate of 35%
|
|
$
|
42,234
|
|
|
$
|
7,772
|
|
|
$
|
(487,649
|
)
|
Increases (reductions) resulting from:
|
|
|
|
|
|
|
||||||
Goodwill
|
|
—
|
|
|
16,382
|
|
|
—
|
|
|||
Adjustments to the valuation allowance
|
|
(64,757
|
)
|
|
(28,865
|
)
|
|
544,949
|
|
|||
Non-deductible compensation
|
|
3,409
|
|
|
1,328
|
|
|
1,893
|
|
|||
State taxes net of federal benefit
|
|
3,464
|
|
|
3,239
|
|
|
(59,406
|
)
|
|||
State tax rate change
|
|
15,496
|
|
|
—
|
|
|
—
|
|
|||
Other
|
|
154
|
|
|
144
|
|
|
213
|
|
|||
Total income tax provision
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
•
|
the level of planned drilling activities;
|
•
|
the results of our ongoing drilling programs;
|
•
|
our ability to fund, finance or repay financing incurred in connection with acquisitions of oil and natural gas properties;
|
•
|
the integration of acquisitions of oil and natural gas properties or other assets;
|
•
|
our ability to effectively manage operating, general and administrative expenses and capital expenditure programs;
|
•
|
reduced oil and natural gas revenues resulting from, among other things, depressed oil and natural gas prices and lower production from reductions to our drilling and development activities;
|
•
|
our ability to mitigate commodity price volatility with derivative financial instruments;
|
•
|
our ability to meet minimum volume commitments under firm transportation agreements and other fixed commitments;
|
•
|
potential acquisitions and/or dispositions of oil and natural gas properties or other assets, including our ability to obtain financing in order to fund the acquisition of properties under a participation agreement with a joint venture partner in the Eagle Ford shale;
|
•
|
reductions to our borrowing base; and
|
•
|
our ability to maintain compliance with debt covenants.
|
(in thousands)
|
|
December 31, 2014
|
||
EXCO Resources Credit Agreement
|
|
$
|
202,492
|
|
2018 Notes (1)
|
|
750,000
|
|
|
2022 Notes
|
|
500,000
|
|
|
Total debt
|
|
$
|
1,452,492
|
|
Net debt
|
|
$
|
1,382,217
|
|
Borrowing base (2)
|
|
$
|
900,000
|
|
Unused borrowing base (3)
|
|
$
|
690,935
|
|
Cash (4)
|
|
$
|
70,275
|
|
Unused borrowing base plus cash
|
|
$
|
761,210
|
|
(1)
|
Excludes unamortized discount of
$6.0 million
at
December 31, 2014
.
|
(2)
|
On February 6, 2015, our borrowing base was reduced to
$725.0 million
, which would have resulted in liquidity of
$586.2 million
on a pro forma basis if the borrowing base redetermination had occurred on December 31, 2014.
|
(3)
|
Net of
$6.6 million
in letters of credit as of
December 31, 2014
.
|
(4)
|
Includes restricted cash of
$24.0 million
at
December 31, 2014
.
|
•
|
our consolidated current ratio (as defined in the EXCO Resources Credit Agreement) of
2.5
to 1.0 exceeded the minimum of at least
1.0
to
1.0
as of the end of any fiscal quarter; and
|
•
|
our ratio of consolidated funded indebtedness to consolidated EBITDAX (as defined in the EXCO Resources Credit Agreement) of
3.9
to
1.0
did not exceed the maximum of
4.5
to
1.0
at the end of any fiscal quarter.
|
•
|
maintain a consolidated current ratio of at least
1.0
to
1.0
as of the end of any fiscal quarter;
|
•
|
maintain a ratio of consolidated EBITDAX to consolidated interest expense ("Interest Coverage Ratio") of at least
2.0
to
1.0
as of the end of any fiscal quarter;
|
•
|
not permit our ratio of senior secured indebtedness to consolidated EBITDAX ("Secured Indebtedness Ratio") to be greater than
2.50
to
1.0
as of the end of any fiscal quarter; and
|
•
|
not permit our ratio of consolidated funded indebtedness to consolidated EBITDAX ("Leverage Ratio") as of the end of any fiscal quarter to be greater than the ratio set forth for the following periods:
|
Period
|
|
Ratio
|
The fiscal quarter ending December 31, 2016
|
|
6.00 to 1.00
|
The fiscal quarter ending March 31, 2017 and June 30, 2017
|
|
5.75 to 1.00
|
The fiscal quarter ending September 30, 2017
|
|
5.25 to 1.00
|
The fiscal quarter ending December 31, 2017
|
|
4.75 to 1.00
|
Each fiscal quarter ending thereafter
|
|
4.50 to 1.00
|
|
|
Year Ended December 31,
|
||||||||||
(in thousands)
|
|
2014
|
|
2013
|
|
2012
|
||||||
Net cash provided by operating activities
|
|
$
|
362,093
|
|
|
$
|
350,634
|
|
|
$
|
514,786
|
|
Net cash used in investing activities
|
|
(221,588
|
)
|
|
(252,478
|
)
|
|
(427,094
|
)
|
|||
Net cash used in financing activities
|
|
(144,683
|
)
|
|
(93,317
|
)
|
|
(74,045
|
)
|
|||
Net increase (decrease) in cash
|
|
$
|
(4,178
|
)
|
|
$
|
4,839
|
|
|
$
|
13,647
|
|
|
|
Year Ended December 31,
|
||||||||||
(in thousands)
|
|
2014
|
|
2013
|
|
2012
|
||||||
Capital expenditures:
|
|
|
|
|
|
|
||||||
Lease purchases and seismic
|
|
$
|
10,477
|
|
|
$
|
25,052
|
|
|
$
|
49,158
|
|
Development capital expenditures
|
|
356,344
|
|
|
265,120
|
|
|
403,342
|
|
|||
Field operations, gathering and water pipelines
|
|
20,256
|
|
|
12,379
|
|
|
1,044
|
|
|||
Corporate and other
|
|
37,198
|
|
|
37,287
|
|
|
48,303
|
|
|||
Total capital expenditures excluding oil and natural gas property acquisitions
|
|
424,275
|
|
|
339,838
|
|
|
501,847
|
|
|||
Oil and natural gas property acquisitions (1)
|
|
10,562
|
|
|
942,946
|
|
|
3,349
|
|
|||
Total capital expenditures including oil and natural gas property acquisitions
|
|
$
|
434,837
|
|
|
$
|
1,282,784
|
|
|
$
|
505,196
|
|
(1)
|
The oil and natural gas property acquisitions of
$942.9 million
during 2013 included the Eagle Ford and Haynesville assets. This amount was reduced by
$130.9 million
from the sale of a portion of the undeveloped acreage we acquired in the Eagle Ford shale to a joint venture partner.
|
|
|
Gross Wells Spud (1)
|
|
Net Wells Spud (1)
|
|
Net Wells Completed (1)
|
|
Drilling & Completion
|
|
Other Capital
|
|
Total Capital
|
|||||||||
(in millions, except wells)
|
|
|
|
|
|
|
|||||||||||||||
East Texas/North Louisiana
|
|
25
|
|
|
11.9
|
|
|
17.6
|
|
|
$
|
150.0
|
|
|
$
|
8.0
|
|
|
$
|
158.0
|
|
South Texas
|
|
23
|
|
|
7.1
|
|
|
10.7
|
|
|
59.0
|
|
|
7.0
|
|
|
66.0
|
|
|||
Appalachia
|
|
2
|
|
|
0.7
|
|
|
0.5
|
|
|
6.0
|
|
|
8.0
|
|
|
14.0
|
|
|||
Corporate and other (2)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
37.0
|
|
|
37.0
|
|
|||
Total
|
|
50
|
|
|
19.7
|
|
|
28.8
|
|
|
$
|
215.0
|
|
|
$
|
60.0
|
|
|
$
|
275.0
|
|
(1)
|
The wells spud and completed within this table only include those operated by EXCO.
|
(2)
|
Includes
$21.0 million
of capitalized interest and $16.0 million of capitalized general and administrative expenses.
|
(in thousands, except prices)
|
|
NYMEX gas volume - Mmbtu
|
|
Weighted average contract price per Mmbtu
|
|
NYMEX oil volume - Bbls
|
|
Weighted average contract price per Bbl
|
||||||
Swaps:
|
|
|
|
|
|
|
|
|
||||||
2015
|
|
42,888
|
|
|
$
|
4.20
|
|
|
1,095
|
|
|
$
|
91.09
|
|
Basis swaps:
|
|
|
|
|
|
|
|
|
||||||
2015
|
|
—
|
|
|
—
|
|
|
91
|
|
|
6.10
|
|
||
Call options:
|
|
|
|
|
|
|
|
|
||||||
2015
|
|
20,075
|
|
|
4.29
|
|
|
365
|
|
|
100.00
|
|
||
Three-way collars:
|
|
|
|
|
|
|
|
|
||||||
2015
|
|
27,375
|
|
|
|
|
—
|
|
|
|
||||
Sold call
|
|
|
|
4.47
|
|
|
|
|
—
|
|
||||
Purchased put
|
|
|
|
3.83
|
|
|
|
|
—
|
|
||||
Sold put
|
|
|
|
3.33
|
|
|
|
|
—
|
|
||||
2016
|
|
10,980
|
|
|
|
|
—
|
|
|
|
||||
Sold call
|
|
|
|
4.80
|
|
|
|
|
—
|
|
||||
Purchased put
|
|
|
|
3.90
|
|
|
|
|
—
|
|
||||
Sold put
|
|
|
|
3.40
|
|
|
|
|
—
|
|
|
|
Payments due by period
|
||||||||||||||||||
(in thousands)
|
|
Less than one year
|
|
One to three years
|
|
Three to five years
|
|
More than five years
|
|
Total
|
||||||||||
EXCO Resources Credit Agreement (1)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
202,492
|
|
|
$
|
—
|
|
|
$
|
202,492
|
|
Senior Notes (2)
|
|
—
|
|
|
—
|
|
|
750,000
|
|
|
500,000
|
|
|
1,250,000
|
|
|||||
Gathering and firm transportation services (3)
|
|
136,040
|
|
|
266,289
|
|
|
218,200
|
|
|
101,618
|
|
|
722,147
|
|
|||||
Other fixed commitments (4)
|
|
17,332
|
|
|
18,696
|
|
|
5,613
|
|
|
3,530
|
|
|
45,171
|
|
|||||
Drilling contracts (5)
|
|
22,191
|
|
|
2,538
|
|
|
—
|
|
|
—
|
|
|
24,729
|
|
|||||
Operating leases and other
|
|
5,912
|
|
|
9,070
|
|
|
6,145
|
|
|
1,623
|
|
|
22,750
|
|
|||||
Total contractual obligations
|
|
$
|
181,475
|
|
|
$
|
296,593
|
|
|
$
|
1,182,450
|
|
|
$
|
606,771
|
|
|
$
|
2,267,289
|
|
(1)
|
The EXCO Resources Credit Agreement matures on July 31, 2018. The interest rate grid on the revolving credit facility of the EXCO Resources Credit Agreement ranges from LIBOR plus 175 bps to 275 bps (or ABR plus 75 bps to 175 bps), depending on the percentages of drawn balances to the borrowing base.
|
(2)
|
The 2018 Notes are due on September 15, 2018. The annual interest obligation is
$56.3 million
. The 2022 Notes are due on April 15, 2022. The annual interest obligation is
$42.5 million
.
|
(3)
|
Gathering and firm transportation services reflect contracts whereby EXCO commits to transport a minimum quantity of natural gas on a gatherer's system or a shippers’ pipeline. Whether or not EXCO delivers the minimum quantity, we pay the fees as if the quantities were delivered. These expenses represent our gross commitments under these contracts and a portion of these costs will be incurred by working interest and other owners.
|
(4)
|
Other fixed commitments are primarily related to completion service contracts and minimum sales commitments under marketing contracts.
|
(5)
|
Drilling contracts represent the early termination fees we would incur if we terminated our contracts for drilling rigs at December 31, 2014. The actual drilling costs under these contracts will be incurred by working interest owners in the development of the related properties.
|
Item 8.
|
Financial Statements and Supplementary Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
By:
|
/s/ Harold L. Hickey
|
|
By:
|
/s/ Richard A. Burnett
|
Title:
|
President and Chief Operating Officer
|
|
Title:
|
Vice President, Chief Financial Officer
|
|
|
|
|
and Chief Accounting Officer
|
Dallas, Texas
|
|
|
|
|
February 25, 2015
|
|
|
|
|
(in thousands)
|
|
December 31,
2014 |
|
December 31,
2013 |
||||
|
|
|
|
|
||||
Assets
|
|
|
|
|
||||
Current assets:
|
|
|
|
|
||||
Cash and cash equivalents
|
|
$
|
46,305
|
|
|
$
|
50,483
|
|
Restricted cash
|
|
23,970
|
|
|
20,570
|
|
||
Accounts receivable, net:
|
|
|
|
|
||||
Oil and natural gas
|
|
81,720
|
|
|
128,352
|
|
||
Joint interest
|
|
65,398
|
|
|
70,759
|
|
||
Other
|
|
8,945
|
|
|
18,022
|
|
||
Derivative financial instruments
|
|
97,278
|
|
|
8,226
|
|
||
Inventory and other
|
|
7,150
|
|
|
9,442
|
|
||
Total current assets
|
|
330,766
|
|
|
305,854
|
|
||
Equity investments
|
|
55,985
|
|
|
57,562
|
|
||
Oil and natural gas properties (full cost accounting method):
|
|
|
|
|
||||
Unproved oil and natural gas properties and development costs not being amortized
|
|
276,025
|
|
|
425,307
|
|
||
Proved developed and undeveloped oil and natural gas properties
|
|
3,852,073
|
|
|
3,554,210
|
|
||
Accumulated depletion
|
|
(2,414,461
|
)
|
|
(2,183,464
|
)
|
||
Oil and natural gas properties, net
|
|
1,713,637
|
|
|
1,796,053
|
|
||
Gathering assets
|
|
1,488
|
|
|
33,473
|
|
||
Accumulated depreciation and amortization
|
|
(168
|
)
|
|
(10,338
|
)
|
||
Gathering assets, net
|
|
1,320
|
|
|
23,135
|
|
||
Office, field and other assets, net
|
|
23,324
|
|
|
27,233
|
|
||
Deferred financing costs, net
|
|
30,636
|
|
|
28,807
|
|
||
Derivative financial instruments
|
|
2,138
|
|
|
6,829
|
|
||
Deferred income taxes
|
|
35,935
|
|
|
—
|
|
||
Goodwill
|
|
163,155
|
|
|
163,155
|
|
||
Total assets
|
|
$
|
2,356,896
|
|
|
$
|
2,408,628
|
|
(in thousands, except per share and share data)
|
|
December 31,
2014 |
|
December 31,
2013 |
||||
|
|
|
|
|
||||
Liabilities and shareholders’ equity
|
|
|
|
|
||||
Current liabilities:
|
|
|
|
|
||||
Accounts payable and accrued liabilities
|
|
$
|
110,211
|
|
|
$
|
109,217
|
|
Revenues and royalties payable
|
|
152,651
|
|
|
154,862
|
|
||
Drilling advances
|
|
37,648
|
|
|
22,971
|
|
||
Accrued interest payable
|
|
26,265
|
|
|
18,144
|
|
||
Current portion of asset retirement obligations
|
|
1,769
|
|
|
191
|
|
||
Income taxes payable
|
|
—
|
|
|
—
|
|
||
Deferred income taxes
|
|
35,935
|
|
|
—
|
|
||
Derivative financial instruments
|
|
892
|
|
|
11,919
|
|
||
Current maturities of long-term debt
|
|
—
|
|
|
31,866
|
|
||
Total current liabilities
|
|
365,371
|
|
|
349,170
|
|
||
Long-term debt
|
|
1,446,535
|
|
|
1,858,912
|
|
||
Derivative financial instruments
|
|
—
|
|
|
9,671
|
|
||
Asset retirement obligations and other long-term liabilities
|
|
34,986
|
|
|
42,970
|
|
||
Commitments and contingencies
|
|
—
|
|
|
—
|
|
||
Shareholders’ equity:
|
|
|
|
|
||||
Common shares, $0.001 par value; 350,000,000 authorized shares; 274,351,756 shares issued and 273,773,714 shares outstanding at December 31, 2014; 218,783,540 shares issued and 218,244,319 shares outstanding at December 31, 2013
|
|
270
|
|
|
215
|
|
||
Subscription rights, $0.001 par value, none issued and outstanding at December 31, 2014; 54,574,734 issued and outstanding at December 31, 2013
|
|
—
|
|
|
55
|
|
||
Additional paid-in capital
|
|
3,502,209
|
|
|
3,219,748
|
|
||
Accumulated deficit
|
|
(2,984,860
|
)
|
|
(3,064,634
|
)
|
||
Treasury shares, at cost; 578,042 at December 31, 2014 and 539,221 at December 31, 2013
|
|
(7,615
|
)
|
|
(7,479
|
)
|
||
Total shareholders’ equity
|
|
510,004
|
|
|
147,905
|
|
||
Total liabilities and shareholders’ equity
|
|
$
|
2,356,896
|
|
|
$
|
2,408,628
|
|
|
|
Year Ended December 31,
|
||||||||||
(in thousands, except per share data)
|
|
2014
|
|
2013
|
|
2012
|
||||||
Revenues:
|
|
|
|
|
|
|
||||||
Oil
|
|
$
|
196,316
|
|
|
$
|
111,440
|
|
|
$
|
62,119
|
|
Natural gas
|
|
457,946
|
|
|
514,309
|
|
|
462,422
|
|
|||
Natural gas liquids
|
|
6,007
|
|
|
8,560
|
|
|
22,068
|
|
|||
Total revenues
|
|
660,269
|
|
|
634,309
|
|
|
546,609
|
|
|||
Costs and expenses:
|
|
|
|
|
|
|
||||||
Oil and natural gas operating costs
|
|
64,467
|
|
|
61,277
|
|
|
77,127
|
|
|||
Production and ad valorem taxes
|
|
29,859
|
|
|
21,971
|
|
|
27,483
|
|
|||
Gathering and transportation
|
|
101,574
|
|
|
100,645
|
|
|
102,875
|
|
|||
Depletion, depreciation and amortization
|
|
263,569
|
|
|
245,775
|
|
|
303,156
|
|
|||
Impairment of oil and natural gas properties
|
|
—
|
|
|
108,546
|
|
|
1,346,749
|
|
|||
Accretion of discount on asset retirement obligations
|
|
2,690
|
|
|
2,514
|
|
|
3,887
|
|
|||
General and administrative
|
|
65,920
|
|
|
91,878
|
|
|
83,818
|
|
|||
(Gain) loss on divestitures and other operating items
|
|
5,315
|
|
|
(177,518
|
)
|
|
17,029
|
|
|||
Total costs and expenses
|
|
533,394
|
|
|
455,088
|
|
|
1,962,124
|
|
|||
Operating income (loss)
|
|
126,875
|
|
|
179,221
|
|
|
(1,415,515
|
)
|
|||
Other income (expense):
|
|
|
|
|
|
|
||||||
Interest expense, net
|
|
(94,284
|
)
|
|
(102,589
|
)
|
|
(73,492
|
)
|
|||
Gain (loss) on derivative financial instruments
|
|
87,665
|
|
|
(320
|
)
|
|
66,133
|
|
|||
Other income (expense)
|
|
241
|
|
|
(828
|
)
|
|
969
|
|
|||
Equity income (loss)
|
|
172
|
|
|
(53,280
|
)
|
|
28,620
|
|
|||
Total other income (expense)
|
|
(6,206
|
)
|
|
(157,017
|
)
|
|
22,230
|
|
|||
Income (loss) before income taxes
|
|
120,669
|
|
|
22,204
|
|
|
(1,393,285
|
)
|
|||
Income tax expense
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Net income (loss)
|
|
$
|
120,669
|
|
|
$
|
22,204
|
|
|
$
|
(1,393,285
|
)
|
Earnings (loss) per common share:
|
|
|
|
|
|
|
||||||
Basic:
|
|
|
|
|
|
|
||||||
Net income (loss)
|
|
$
|
0.45
|
|
|
$
|
0.10
|
|
|
$
|
(6.50
|
)
|
Weighted average common shares outstanding
|
|
268,258
|
|
|
215,011
|
|
|
214,321
|
|
|||
Diluted:
|
|
|
|
|
|
|
||||||
Net income (loss)
|
|
$
|
0.45
|
|
|
$
|
0.10
|
|
|
$
|
(6.50
|
)
|
Weighted average common shares and common share equivalents outstanding
|
|
268,376
|
|
|
230,912
|
|
|
214,321
|
|
|
|
Year Ended December 31,
|
||||||||||
(in thousands)
|
|
2014
|
|
2013
|
|
2012
|
||||||
Operating Activities:
|
|
|
|
|
|
|
||||||
Net income (loss)
|
|
$
|
120,669
|
|
|
$
|
22,204
|
|
|
$
|
(1,393,285
|
)
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
|
||||||
Depletion, depreciation and amortization
|
|
263,569
|
|
|
245,775
|
|
|
303,156
|
|
|||
Share-based compensation expense
|
|
4,962
|
|
|
10,748
|
|
|
8,926
|
|
|||
Accretion of discount on asset retirement obligations
|
|
2,690
|
|
|
2,514
|
|
|
3,887
|
|
|||
Impairment of oil and natural gas properties
|
|
—
|
|
|
108,546
|
|
|
1,346,749
|
|
|||
(Income) loss from equity investments
|
|
(172
|
)
|
|
53,280
|
|
|
(28,620
|
)
|
|||
(Gain) loss on derivative financial instruments
|
|
(87,665
|
)
|
|
320
|
|
|
(66,133
|
)
|
|||
Cash settlements (payments) of derivative financial instruments
|
|
(18,991
|
)
|
|
42,119
|
|
|
202,078
|
|
|||
Amortization of deferred financing costs and discount on debt issuance
|
|
12,055
|
|
|
29,624
|
|
|
9,788
|
|
|||
(Gain) loss on divestitures and other non-operating items
|
|
(17
|
)
|
|
(185,163
|
)
|
|
1,303
|
|
|||
Effect of changes in:
|
|
|
|
|
|
|
||||||
Accounts receivable
|
|
52,007
|
|
|
(46,176
|
)
|
|
112,919
|
|
|||
Other current assets
|
|
(2,609
|
)
|
|
9,627
|
|
|
7,090
|
|
|||
Accounts payable and other current liabilities
|
|
15,595
|
|
|
57,216
|
|
|
6,928
|
|
|||
Net cash provided by operating activities
|
|
362,093
|
|
|
350,634
|
|
|
514,786
|
|
|||
Investing Activities:
|
|
|
|
|
|
|
||||||
Additions to oil and natural gas properties, gathering assets and equipment
|
|
(391,776
|
)
|
|
(320,538
|
)
|
|
(534,175
|
)
|
|||
Property acquisitions
|
|
(10,790
|
)
|
|
(976,714
|
)
|
|
(2,748
|
)
|
|||
Proceeds from disposition of property and equipment
|
|
187,655
|
|
|
749,628
|
|
|
38,045
|
|
|||
Restricted cash
|
|
(3,400
|
)
|
|
49,515
|
|
|
85,840
|
|
|||
Net changes in advances to joint ventures
|
|
(5,026
|
)
|
|
10,645
|
|
|
851
|
|
|||
Equity method investments
|
|
1,749
|
|
|
236,289
|
|
|
(14,907
|
)
|
|||
Other
|
|
—
|
|
|
(1,303
|
)
|
|
—
|
|
|||
Net cash used in investing activities
|
|
(221,588
|
)
|
|
(252,478
|
)
|
|
(427,094
|
)
|
|||
Financing Activities:
|
|
|
|
|
|
|
||||||
Borrowings under credit agreements
|
|
100,000
|
|
|
1,004,523
|
|
|
53,000
|
|
|||
Repayments under credit agreements
|
|
(964,970
|
)
|
|
(1,022,785
|
)
|
|
(93,000
|
)
|
|||
Proceeds received from issuance of 2022 Notes
|
|
500,000
|
|
|
—
|
|
|
—
|
|
|||
Proceeds from issuance of common shares, net
|
|
271,773
|
|
|
1,712
|
|
|
1,968
|
|
|||
Payment of common share dividends
|
|
(41,060
|
)
|
|
(43,214
|
)
|
|
(34,358
|
)
|
|||
Deferred financing costs and other
|
|
(10,290
|
)
|
|
(33,553
|
)
|
|
(1,655
|
)
|
|||
Payments of common shares repurchased
|
|
(136
|
)
|
|
—
|
|
|
—
|
|
|||
Net cash used in financing activities
|
|
(144,683
|
)
|
|
(93,317
|
)
|
|
(74,045
|
)
|
|||
Net increase (decrease) in cash
|
|
(4,178
|
)
|
|
4,839
|
|
|
13,647
|
|
|||
Cash at beginning of period
|
|
50,483
|
|
|
45,644
|
|
|
31,997
|
|
|||
Cash at end of period
|
|
$
|
46,305
|
|
|
$
|
50,483
|
|
|
$
|
45,644
|
|
Supplemental Cash Flow Information:
|
|
|
|
|
|
|
||||||
Cash interest payments
|
|
$
|
91,735
|
|
|
$
|
88,936
|
|
|
$
|
86,298
|
|
Income tax payments
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Supplemental non-cash investing and financing activities:
|
|
|
|
|
|
|
||||||
Capitalized share-based compensation
|
|
$
|
5,498
|
|
|
$
|
7,288
|
|
|
$
|
7,513
|
|
Capitalized interest
|
|
20,060
|
|
|
18,729
|
|
|
23,809
|
|
|||
Issuance of common shares for director services
|
|
235
|
|
|
93
|
|
|
597
|
|
|||
Debt eliminated upon sale of Compass and assumed upon formation of Compass, net for the years ended December 31, 2014 and 2013, respectively
|
|
(83,246
|
)
|
|
58,613
|
|
|
—
|
|
|||
Issuance of subscription rights
|
|
—
|
|
|
55
|
|
|
—
|
|
|
|
Common Shares
|
|
Subscription Rights
|
|
Treasury Shares
|
|
Additional paid-in capital
|
|
Accumulated deficit
|
|
Total shareholders’ equity
|
|||||||||||||||||||||
(in thousands)
|
|
Shares
|
|
Amount
|
|
Shares
|
|
Amount
|
|
Shares
|
|
Amount
|
|
|
|
||||||||||||||||||
Balance at December 31, 2011
|
|
217,245
|
|
|
$
|
215
|
|
|
—
|
|
|
$
|
—
|
|
|
(539
|
)
|
|
$
|
(7,479
|
)
|
|
$
|
3,181,063
|
|
|
$
|
(1,615,467
|
)
|
|
$
|
1,558,332
|
|
Issuance of common shares
|
|
266
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,565
|
|
|
—
|
|
|
2,565
|
|
||||||
Share-based compensation
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
16,439
|
|
|
—
|
|
|
16,439
|
|
||||||
Restricted shares issued, net of cancellations
|
|
615
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Common share dividends
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(34,658
|
)
|
|
(34,658
|
)
|
||||||
Net income
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,393,285
|
)
|
|
(1,393,285
|
)
|
||||||
Balance at December 31, 2012
|
|
218,126
|
|
|
$
|
215
|
|
|
—
|
|
|
$
|
—
|
|
|
(539
|
)
|
|
$
|
(7,479
|
)
|
|
$
|
3,200,067
|
|
|
$
|
(3,043,410
|
)
|
|
$
|
149,393
|
|
Issuance of common shares
|
|
228
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,805
|
|
|
—
|
|
|
1,805
|
|
||||||
Share-based compensation
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
17,931
|
|
|
—
|
|
|
17,931
|
|
||||||
Restricted shares issued, net of cancellations
|
|
429
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Common share dividends
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(43,428
|
)
|
|
(43,428
|
)
|
||||||
Issuance of subscription rights
|
|
—
|
|
|
—
|
|
|
54,575
|
|
|
55
|
|
|
—
|
|
|
—
|
|
|
(55
|
)
|
|
—
|
|
|
—
|
|
||||||
Net income
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
22,204
|
|
|
22,204
|
|
||||||
Balance at December 31, 2013
|
|
218,783
|
|
|
$
|
215
|
|
|
54,575
|
|
|
$
|
55
|
|
|
(539
|
)
|
|
$
|
(7,479
|
)
|
|
$
|
3,219,748
|
|
|
$
|
(3,064,634
|
)
|
|
$
|
147,905
|
|
Issuance of common shares
|
|
54,582
|
|
|
55
|
|
|
(54,575
|
)
|
|
(55
|
)
|
|
—
|
|
|
—
|
|
|
272,008
|
|
|
—
|
|
|
272,008
|
|
||||||
Share-based compensation
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10,453
|
|
|
—
|
|
|
10,453
|
|
||||||
Restricted shares issued, net of cancellations
|
|
987
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Common share dividends
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(40,895
|
)
|
|
(40,895
|
)
|
||||||
Treasury share repurchases
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(39
|
)
|
|
(136
|
)
|
|
—
|
|
|
—
|
|
|
(136
|
)
|
||||||
Net income
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
120,669
|
|
|
120,669
|
|
||||||
Balance at December 31, 2014
|
|
274,352
|
|
|
$
|
270
|
|
|
—
|
|
|
$
|
—
|
|
|
(578
|
)
|
|
$
|
(7,615
|
)
|
|
$
|
3,502,209
|
|
|
$
|
(2,984,860
|
)
|
|
$
|
510,004
|
|
1.
|
Organization and basis of presentation
|
2.
|
Summary of significant accounting policies
|
|
|
December 31,
|
||||||||||
(in thousands)
|
|
2014
|
|
2013
|
|
2012
|
||||||
Asset retirement obligations at beginning of period
|
|
$
|
42,954
|
|
|
$
|
61,864
|
|
|
$
|
58,088
|
|
Activity during the period:
|
|
|
|
|
|
|
||||||
Liabilities incurred during the period
|
|
576
|
|
|
514
|
|
|
971
|
|
|||
Revisions in estimated assumptions
|
|
—
|
|
|
1,268
|
|
|
—
|
|
|||
Liabilities settled during the period
|
|
(33
|
)
|
|
(187
|
)
|
|
(338
|
)
|
|||
Adjustment to liability due to acquisitions
|
|
107
|
|
|
5,566
|
|
|
—
|
|
|||
Adjustment to liability due to divestitures (1)
|
|
(9,539
|
)
|
|
(28,585
|
)
|
|
(744
|
)
|
|||
Accretion of discount
|
|
2,690
|
|
|
2,514
|
|
|
3,887
|
|
|||
Asset retirement obligations at end of period
|
|
36,755
|
|
|
42,954
|
|
|
61,864
|
|
|||
Less current portion
|
|
1,769
|
|
|
191
|
|
|
1,200
|
|
|||
Long-term portion
|
|
$
|
34,986
|
|
|
$
|
42,763
|
|
|
$
|
60,664
|
|
(1)
|
For the year ended December 31, 2014, the adjustment to liability due to divestitures consisted primarily of
$9.4 million
from the sale of our interest in Compass. For the year ended December 31, 2013, the adjustment to liability due to divestitures consisted primarily of
$28.3 million
from the contribution of our certain conventional assets to Compass.
|
3.
|
Acquisitions, divestitures and other significant events
|
Purchase Price Allocation (in thousands):
|
|
Haynesville Acquired Properties
|
|
Eagle Ford Acquired Properties
|
||||
Assets acquired:
|
|
|
|
|
||||
Unproved oil and natural gas properties
|
|
$
|
2,319
|
|
|
$
|
227,869
|
|
Proved developed and undeveloped oil and natural gas properties
|
|
282,918
|
|
|
437,616
|
|
||
Liabilities assumed:
|
|
|
|
|
||||
Accounts payable and accrued liabilities
|
|
—
|
|
|
(580
|
)
|
||
Revenues and royalties payable
|
|
(3,526
|
)
|
|
—
|
|
||
Asset retirement obligations
|
|
(610
|
)
|
|
(3,060
|
)
|
||
Total purchase price
|
|
$
|
281,101
|
|
|
$
|
661,845
|
|
|
|
Year Ended December 31,
|
||||||
(in thousands, except for per share data)
|
|
2013
|
|
2012
|
||||
Oil and natural gas revenues
|
|
$
|
784,628
|
|
|
$
|
715,286
|
|
Net income (loss) (1)
|
|
$
|
38,663
|
|
|
$
|
(1,398,169
|
)
|
Basic earnings (loss) per share
|
|
$
|
0.18
|
|
|
$
|
(6.52
|
)
|
Diluted earnings (loss) per share
|
|
$
|
0.17
|
|
|
$
|
(6.52
|
)
|
(1)
|
Net loss for the year ended December 31, 2012 was primarily due to the impairment of our oil and natural gas properties due to the significant decline in natural gas prices.
|
4.
|
Derivative financial instruments
|
(in thousands)
|
|
December 31, 2014
|
|
December 31, 2013
|
||||
Derivative financial instruments - Current assets
|
|
$
|
97,278
|
|
|
$
|
8,226
|
|
Derivative financial instruments - Long-term assets
|
|
2,138
|
|
|
6,829
|
|
||
Derivative financial instruments - Current liabilities
|
|
(892
|
)
|
|
(11,919
|
)
|
||
Derivative financial instruments - Long-term liabilities
|
|
—
|
|
|
(9,671
|
)
|
||
Net derivative financial instruments
|
|
$
|
98,524
|
|
|
$
|
(6,535
|
)
|
|
|
Year Ended December 31,
|
||||||||||
(in thousands)
|
|
2014
|
|
2013
|
|
2012
|
||||||
Gain (loss) on derivative financial instruments
|
|
$
|
87,665
|
|
|
$
|
(320
|
)
|
|
$
|
66,133
|
|
(in thousands, except prices)
|
|
Volume Mmbtu/Bbl
|
|
Weighted average strike price per Mmbtu/Bbl
|
|
Fair value at December 31, 2014
|
|||||
Natural gas:
|
|
|
|
|
|
|
|||||
Swaps:
|
|
|
|
|
|
|
|||||
2015
|
|
42,888
|
|
|
$
|
4.20
|
|
|
49,926
|
|
|
Call options:
|
|
|
|
|
|
|
|||||
2015
|
|
20,075
|
|
|
4.29
|
|
|
(784
|
)
|
||
Three-way collars:
|
|
|
|
|
|
|
|||||
2015
|
|
27,375
|
|
|
|
|
10,205
|
|
|||
Sold call
|
|
|
|
4.47
|
|
|
|
||||
Purchased put
|
|
|
|
3.83
|
|
|
|
||||
Sold put
|
|
|
|
3.33
|
|
|
|
||||
2016
|
|
10,980
|
|
|
|
|
2,138
|
|
|||
Sold call
|
|
|
|
4.80
|
|
|
|
||||
Purchased put
|
|
|
|
3.90
|
|
|
|
||||
Sold put
|
|
|
|
3.40
|
|
|
|
||||
Total natural gas
|
|
|
|
|
|
$
|
61,485
|
|
|||
Oil:
|
|
|
|
|
|
|
|||||
Swaps:
|
|
|
|
|
|
|
|||||
2015
|
|
1,095
|
|
|
$
|
91.09
|
|
|
36,797
|
|
|
Basis swaps:
|
|
|
|
|
|
|
|||||
2015
|
|
91
|
|
|
6.10
|
|
|
350
|
|
||
Call options:
|
|
|
|
|
|
|
|||||
2015
|
|
365
|
|
|
100.00
|
|
|
(108
|
)
|
||
Total oil
|
|
|
|
|
|
$
|
37,039
|
|
|||
Total oil and natural gas derivative financial instruments
|
|
|
|
|
|
$
|
98,524
|
|
5.
|
Fair value measurements
|
|
|
December 31, 2014
|
||||||||||||||
(in thousands)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
Oil and natural gas derivative financial instruments
|
|
$
|
—
|
|
|
$
|
98,524
|
|
|
$
|
—
|
|
|
$
|
98,524
|
|
|
|
December 31, 2013
|
||||||||||||||
(in thousands)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
Oil and natural gas derivative financial instruments
|
|
$
|
—
|
|
|
$
|
(6,535
|
)
|
|
$
|
—
|
|
|
$
|
(6,535
|
)
|
|
|
December 31, 2014
|
||||||||||||||
(in thousands)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
2018 Notes
|
|
$
|
558,750
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
558,750
|
|
2022 Notes
|
|
373,500
|
|
|
—
|
|
|
—
|
|
|
373,500
|
|
||||
|
|
December 31, 2013
|
||||||||||||||
(in thousands)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
2018 Notes
|
|
$
|
714,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
714,000
|
|
Term Loan
|
|
298,500
|
|
|
—
|
|
|
—
|
|
|
298,500
|
|
6.
|
Debt
|
(in thousands)
|
|
December 31, 2014
|
|
December 31, 2013
|
||||
Revolving credit facility under EXCO Resources Credit Agreement
|
|
$
|
202,492
|
|
|
$
|
763,866
|
|
Term Loan under EXCO Resources Credit Agreement
|
|
—
|
|
|
298,500
|
|
||
Unamortized discount on Term Loan
|
|
—
|
|
|
(2,780
|
)
|
||
2018 Notes
|
|
750,000
|
|
|
750,000
|
|
||
Unamortized discount on 2018 Notes
|
|
(5,957
|
)
|
|
(7,293
|
)
|
||
2022 Notes
|
|
500,000
|
|
|
—
|
|
||
Total debt excluding Compass
|
|
1,446,535
|
|
|
1,802,293
|
|
||
Compass Production Partners Credit Agreement
|
|
—
|
|
|
88,485
|
|
||
Total debt
|
|
1,446,535
|
|
|
1,890,778
|
|
||
Less amounts due within one year
|
|
—
|
|
|
31,866
|
|
||
Total debt due after one year
|
|
$
|
1,446,535
|
|
|
$
|
1,858,912
|
|
•
|
maintain a consolidated current ratio (as defined in the EXCO Resources Credit Agreement) of at least
1.0
to
1.0
as of the end of any fiscal quarter; and
|
•
|
not permit our ratio of consolidated funded indebtedness to consolidated EBITDAX (as defined in the EXCO Resources Credit Agreement) to be greater than
4.5
to
1.0
at the end of any fiscal quarter.
|
•
|
maintain a consolidated current ratio of at least
1.0
to
1.0
as of the end of any fiscal quarter;
|
•
|
maintain a ratio of consolidated EBITDAX to consolidated interest expense ("Interest Coverage Ratio") of at least
2.0
to
1.0
as of the end of any fiscal quarter;
|
•
|
not permit our ratio of senior secured indebtedness to consolidated EBITDAX ("Secured Indebtedness Ratio") to be greater than
2.50
to
1.0
as of the end of any fiscal quarter; and
|
•
|
not permit our ratio of consolidated funded indebtedness to consolidated EBITDAX ("Leverage Ratio") as of the end of any fiscal quarter to be greater than the ratio set forth for the following periods:
|
Period
|
|
Ratio
|
The fiscal quarter ending December 31, 2016
|
|
6.00 to 1.00
|
The fiscal quarter ending March 31, 2017 and June 30, 2017
|
|
5.75 to 1.00
|
The fiscal quarter ending September 30, 2017
|
|
5.25 to 1.00
|
The fiscal quarter ending December 31, 2017
|
|
4.75 to 1.00
|
Each fiscal quarter ending thereafter
|
|
4.50 to 1.00
|
•
|
incur or guarantee additional debt and issue certain types of preferred shares;
|
•
|
pay dividends on our capital stock or redeem, repurchase or retire our capital stock or subordinated debt;
|
•
|
make certain investments;
|
•
|
create liens on our assets;
|
•
|
enter into sale/leaseback transactions;
|
•
|
create restrictions on the ability of our restricted subsidiaries to pay dividends or make other payments to us;
|
•
|
engage in transactions with our affiliates;
|
•
|
transfer or issue shares of stock of subsidiaries;
|
•
|
transfer or sell assets; and
|
•
|
consolidate, merge or transfer all or substantially all of our assets and the assets of our subsidiaries.
|
7.
|
Environmental regulation
|
8.
|
Commitments and contingencies
|
(in thousands)
|
|
Gathering and firm transportation services
|
|
Other fixed commitments
|
|
Drilling contracts
|
|
Operating leases and other
|
|
Total
|
||||||||||
2015
|
|
$
|
136,040
|
|
|
$
|
17,332
|
|
|
$
|
22,191
|
|
|
$
|
5,912
|
|
|
$
|
181,475
|
|
2016
|
|
133,429
|
|
|
13,253
|
|
|
2,538
|
|
|
5,223
|
|
|
154,443
|
|
|||||
2017
|
|
132,860
|
|
|
5,443
|
|
|
—
|
|
|
3,847
|
|
|
142,150
|
|
|||||
2018
|
|
129,140
|
|
|
3,210
|
|
|
—
|
|
|
3,094
|
|
|
135,444
|
|
|||||
2019
|
|
89,060
|
|
|
2,403
|
|
|
—
|
|
|
3,051
|
|
|
94,514
|
|
|||||
Thereafter
|
|
101,618
|
|
|
3,530
|
|
|
—
|
|
|
1,623
|
|
|
106,771
|
|
|||||
Total
|
|
$
|
722,147
|
|
|
$
|
45,171
|
|
|
$
|
24,729
|
|
|
$
|
22,750
|
|
|
$
|
814,797
|
|
(in Bcf)
|
|
Firm transportation services
|
|
Gathering services
|
||
2015
|
|
293
|
|
|
110
|
|
2016
|
|
272
|
|
|
110
|
|
2017
|
|
269
|
|
|
110
|
|
2018
|
|
269
|
|
|
100
|
|
2019
|
|
269
|
|
|
—
|
|
Thereafter
|
|
299
|
|
|
—
|
|
Total
|
|
1,671
|
|
|
430
|
|
9.
|
Employee benefit plans
|
10.
|
Earnings per share
|
|
|
Year Ended December 31,
|
||||||||||
(in thousands, except per share data)
|
|
2014
|
|
2013
|
|
2012
|
||||||
Basic net income (loss) per common share:
|
|
|
|
|
|
|
||||||
Net income (loss)
|
|
$
|
120,669
|
|
|
$
|
22,204
|
|
|
$
|
(1,393,285
|
)
|
Weighted average common shares outstanding
|
|
268,258
|
|
|
215,011
|
|
|
214,321
|
|
|||
Net income (loss) per basic common share
|
|
$
|
0.45
|
|
|
$
|
0.10
|
|
|
$
|
(6.50
|
)
|
Diluted net income (loss) per common share:
|
|
|
|
|
|
|
||||||
Net income (loss)
|
|
$
|
120,669
|
|
|
$
|
22,204
|
|
|
$
|
(1,393,285
|
)
|
Weighted average common shares outstanding
|
|
268,258
|
|
|
215,011
|
|
|
214,321
|
|
|||
Dilutive effect of:
|
|
|
|
|
|
|
||||||
Stock options
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Restricted shares and restricted share units
|
|
118
|
|
|
420
|
|
|
—
|
|
|||
Subscription rights
|
|
—
|
|
|
15,481
|
|
|
—
|
|
|||
Weighted average common shares and common share equivalents outstanding
|
|
268,376
|
|
|
230,912
|
|
|
214,321
|
|
|||
Net income (loss) per diluted common share
|
|
$
|
0.45
|
|
|
$
|
0.10
|
|
|
$
|
(6.50
|
)
|
11.
|
Stock options and awards
|
|
|
Year Ended December 31,
|
||||||||||
(in thousands)
|
|
2014
|
|
2013
|
|
2012
|
||||||
Share-based compensation expense
|
|
$
|
4,962
|
|
|
$
|
10,748
|
|
|
$
|
8,926
|
|
Share-based compensation capitalized
|
|
5,498
|
|
|
7,288
|
|
|
7,513
|
|
|||
Total share-based compensation
|
|
$
|
10,460
|
|
|
$
|
18,036
|
|
|
$
|
16,439
|
|
|
|
Stock Options
|
|
Weighted average exercise price per share
|
|
Weighted average remaining terms (in years)
|
|
Aggregate intrinsic value
|
||||||
Options outstanding at December 31, 2011
|
|
15,670,168
|
|
|
$
|
13.44
|
|
|
|
|
|
|||
Granted
|
|
146,500
|
|
|
8.00
|
|
|
|
|
|
||||
Forfeitures
|
|
(1,543,933
|
)
|
|
16.12
|
|
|
|
|
|
||||
Exercised
|
|
(256,940
|
)
|
|
7.66
|
|
|
|
|
|
||||
Options outstanding at December 31, 2012
|
|
14,015,795
|
|
|
13.20
|
|
|
|
|
|
||||
Granted
|
|
2,886,500
|
|
|
7.48
|
|
|
|
|
|
||||
Forfeitures
|
|
(4,969,877
|
)
|
|
11.32
|
|
|
|
|
|
||||
Exercised
|
|
(220,675
|
)
|
|
7.66
|
|
|
|
|
|
||||
Options outstanding at December 31, 2013
|
|
11,711,743
|
|
|
12.69
|
|
|
|
|
|
||||
Granted
|
|
141,525
|
|
|
5.24
|
|
|
|
|
|
||||
Forfeitures
|
|
(1,700,250
|
)
|
|
12.71
|
|
|
|
|
|
||||
Exercised
|
|
(2,500
|
)
|
|
5.22
|
|
|
|
|
|
||||
Options outstanding at December 31, 2014
|
|
10,150,518
|
|
|
$
|
12.58
|
|
|
3.7
|
|
$
|
—
|
|
|
Options exercisable at December 31, 2014
|
|
9,181,306
|
|
|
$
|
13.15
|
|
|
3.2
|
|
$
|
—
|
|
|
|
2014
|
|
2013
|
|
2012
|
Expected life
|
|
7.5 years
|
|
3.8 to 7.5 years
|
|
3.8 to 7.5 years
|
Risk-free rate of return
|
|
2.25 - 2.61 %
|
|
0.48 - 2.49 %
|
|
0.56 - 1.64 %
|
Volatility
|
|
59.46 - 59.61 %
|
|
49.47 - 59.86 %
|
|
57.34 - 60.24 %
|
Dividend yield
|
|
3.36 - 4.34 %
|
|
2.27 - 3.87 %
|
|
0.52 - 1.92 %
|
|
|
Shares
|
|
Weighted average grant date fair value per share
|
||||
Non-vested shares outstanding at December 31, 2011
|
|
2,562,409
|
|
|
$
|
11.72
|
|
|
Granted
|
|
926,900
|
|
|
7.57
|
|
||
Vested
|
|
(370,448
|
)
|
|
12.89
|
|
||
Forfeited
|
|
(312,496
|
)
|
|
11.89
|
|
||
Non-vested shares outstanding at December 31, 2012
|
|
2,806,365
|
|
|
$
|
10.16
|
|
|
Granted
|
|
556,700
|
|
|
7.15
|
|
||
Vested
|
|
(832,706
|
)
|
|
10.47
|
|
||
Forfeited
|
|
(602,045
|
)
|
|
9.84
|
|
||
Non-vested shares outstanding at December 31, 2013
|
|
1,928,314
|
|
|
$
|
9.26
|
|
|
Granted
|
|
1,339,782
|
|
|
5.20
|
|
||
Vested
|
|
(1,109,866
|
)
|
|
9.79
|
|
||
Forfeited
|
|
(280,301
|
)
|
|
6.89
|
|
||
Non-vested shares outstanding at December 31, 2014
|
|
1,877,929
|
|
|
$
|
6.40
|
|
|
|
Target Price Awards
|
|
TSRs
|
||||||||||
|
|
Shares
|
|
Weighted average grant date fair value per share
|
|
Shares
|
|
Weighted average grant date fair value per share
|
||||||
|
|
|
|
|
||||||||||
Non-vested shares outstanding at December 31, 2012
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
Granted
|
|
736,000
|
|
|
6.36
|
|
|
—
|
|
|
—
|
|
||
Vested
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||
Forfeited
|
|
(261,400
|
)
|
|
6.36
|
|
|
—
|
|
|
—
|
|
||
Non-vested shares outstanding at December 31, 2013
|
|
474,600
|
|
|
$
|
6.36
|
|
|
—
|
|
|
$
|
—
|
|
Granted
|
|
—
|
|
|
—
|
|
|
820,317
|
|
|
7.33
|
|
||
Vested
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||
Forfeited
|
|
(73,200
|
)
|
|
6.36
|
|
|
(104,167
|
)
|
|
7.33
|
|
||
Non-vested shares outstanding at December 31, 2014
|
|
401,400
|
|
|
$
|
6.36
|
|
|
716,150
|
|
|
$
|
7.33
|
|
12.
|
Income taxes
|
|
|
Year ended December 31,
|
||||||||||
(in thousands)
|
|
2014
|
|
2013
|
|
2012
|
||||||
Current:
|
|
|
|
|
|
|
||||||
Federal
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
State
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Total current income tax (benefit)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
||||||
Deferred:
|
|
|
|
|
|
|
||||||
Federal
|
|
$
|
45,797
|
|
|
$
|
25,626
|
|
|
$
|
(485,543
|
)
|
State
|
|
18,960
|
|
|
3,239
|
|
|
(59,406
|
)
|
|||
Valuation allowance
|
|
(64,757
|
)
|
|
(28,865
|
)
|
|
544,949
|
|
|||
Total deferred income tax (benefit)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Total income tax (benefit)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
(in thousands)
|
|
December 31, 2014
|
|
December 31, 2013
|
||||
Current deferred tax assets (liabilities):
|
|
|
|
|
||||
Derivative financial instruments
|
|
$
|
(38,519
|
)
|
|
$
|
—
|
|
Other
|
|
2,584
|
|
|
5,332
|
|
||
Valuation allowance
|
|
—
|
|
|
(5,332
|
)
|
||
Net current deferred tax assets (liabilities)
|
|
(35,935
|
)
|
|
—
|
|
||
Non-current deferred tax assets:
|
|
|
|
|
||||
Net operating loss and AMT credits carryforwards
|
|
$
|
781,899
|
|
|
$
|
737,399
|
|
Capital loss carryforwards
|
|
40,356
|
|
|
—
|
|
||
Share-based compensation
|
|
14,856
|
|
|
16,060
|
|
||
Oil and natural gas properties, gathering assets, and equipment
|
|
—
|
|
|
47,491
|
|
||
Goodwill
|
|
5,419
|
|
|
9,812
|
|
||
Derivative financial instruments
|
|
—
|
|
|
2,102
|
|
||
Investment in partnerships
|
|
72,988
|
|
|
73,328
|
|
||
Other
|
|
84
|
|
|
85
|
|
||
Total non-current deferred tax assets
|
|
915,602
|
|
|
886,277
|
|
||
Valuation allowance
|
|
(826,852
|
)
|
|
(886,277
|
)
|
||
Total non-current deferred tax assets
|
|
88,750
|
|
|
—
|
|
||
Non-current deferred tax liabilities:
|
|
|
|
|
||||
Oil and natural gas properties, gathering assets, and equipment
|
|
$
|
(51,961
|
)
|
|
$
|
—
|
|
Derivative financial instruments
|
|
(854
|
)
|
|
—
|
|
||
Total non-current deferred tax liabilities
|
|
(52,815
|
)
|
|
—
|
|
||
Net non-current deferred tax assets (liabilities)
|
|
$
|
35,935
|
|
|
$
|
—
|
|
|
|
Year Ended December 31,
|
||||||||||
(in thousands)
|
|
2014
|
|
2013
|
|
2012
|
||||||
Federal income taxes (benefit) provision at statutory rate of 35%
|
|
$
|
42,234
|
|
|
$
|
7,772
|
|
|
$
|
(487,649
|
)
|
Increases (reductions) resulting from:
|
|
|
|
|
|
|
||||||
Goodwill
|
|
—
|
|
|
16,382
|
|
|
—
|
|
|||
Adjustments to the valuation allowance
|
|
(64,757
|
)
|
|
(28,865
|
)
|
|
544,949
|
|
|||
Non-deductible compensation
|
|
3,409
|
|
|
1,328
|
|
|
1,893
|
|
|||
State taxes net of federal benefit
|
|
3,464
|
|
|
3,239
|
|
|
(59,406
|
)
|
|||
State tax rate change
|
|
15,496
|
|
|
—
|
|
|
—
|
|
|||
Other
|
|
154
|
|
|
144
|
|
|
213
|
|
|||
Total income tax provision
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
13.
|
Related party transactions
|
|
|
Year Ended December 31,
|
||||||||||
(in thousands)
|
|
2014
|
|
2013
|
|
2012
|
||||||
Advances to OPCO
|
|
$
|
—
|
|
|
$
|
28,378
|
|
|
$
|
76,729
|
|
Amounts received from OPCO
|
|
53,002
|
|
|
43,632
|
|
|
52,206
|
|
(in thousands)
|
|
December 31, 2014
|
|
December 31, 2013
|
||||
Amounts due to EXCO (1)
|
|
$
|
2,799
|
|
|
$
|
2,283
|
|
Amounts due from EXCO (1)
|
|
—
|
|
|
—
|
|
(1)
|
OPCO is the operator of our wells in the Appalachia JV and we advance funds to OPCO on an as needed basis, which are recorded in "Other current assets" on our Consolidated Balance Sheets. Any amounts we owe to OPCO are netted against the advance until the advances are utilized. If the advances are fully utilized, we record amounts owed in "Accounts payable and accrued liabilities" on our Consolidated Balance Sheets.
|
14.
|
Dividends
|
15.
|
Rights Offering and other equity transactions
|
16.
|
Condensed consolidating financial statements
|
•
|
Resources;
|
•
|
the Guarantor Subsidiaries;
|
•
|
the Non-Guarantor Subsidiaries;
|
•
|
elimination entries necessary to consolidate Resources, the Guarantor Subsidiaries and the Non-Guarantor Subsidiaries; and
|
•
|
EXCO on a consolidated basis.
|
(in thousands)
|
|
Resources
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Assets
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Current assets:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash and cash equivalents
|
|
$
|
86,837
|
|
|
$
|
(40,532
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
46,305
|
|
Restricted cash
|
|
—
|
|
|
23,970
|
|
|
—
|
|
|
—
|
|
|
23,970
|
|
|||||
Other current assets
|
|
110,145
|
|
|
150,346
|
|
|
—
|
|
|
—
|
|
|
260,491
|
|
|||||
Total current assets
|
|
196,982
|
|
|
133,784
|
|
|
—
|
|
|
—
|
|
|
330,766
|
|
|||||
Equity investments
|
|
—
|
|
|
—
|
|
|
55,985
|
|
|
—
|
|
|
55,985
|
|
|||||
Oil and natural gas properties (full cost accounting method):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Unproved oil and natural gas properties and development costs not being amortized
|
|
—
|
|
|
276,025
|
|
|
—
|
|
|
—
|
|
|
276,025
|
|
|||||
Proved developed and undeveloped oil and natural gas properties
|
|
335,838
|
|
|
3,516,235
|
|
|
—
|
|
|
—
|
|
|
3,852,073
|
|
|||||
Accumulated depletion
|
|
(330,771
|
)
|
|
(2,083,690
|
)
|
|
—
|
|
|
—
|
|
|
(2,414,461
|
)
|
|||||
Oil and natural gas properties, net
|
|
5,067
|
|
|
1,708,570
|
|
|
—
|
|
|
—
|
|
|
1,713,637
|
|
|||||
Gathering, office, field and other assets, net
|
|
1,269
|
|
|
23,375
|
|
|
—
|
|
|
—
|
|
|
24,644
|
|
|||||
Investments in and advances to affiliates, net
|
|
1,746,931
|
|
|
—
|
|
|
—
|
|
|
(1,746,931
|
)
|
|
—
|
|
|||||
Deferred financing costs, net
|
|
30,636
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
30,636
|
|
|||||
Derivative financial instruments
|
|
2,138
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,138
|
|
|||||
Goodwill
|
|
13,293
|
|
|
149,862
|
|
|
—
|
|
|
—
|
|
|
163,155
|
|
|||||
Deferred income taxes
|
|
35,935
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
35,935
|
|
|||||
Total assets
|
|
$
|
2,032,251
|
|
|
$
|
2,015,591
|
|
|
$
|
55,985
|
|
|
$
|
(1,746,931
|
)
|
|
$
|
2,356,896
|
|
Liabilities and shareholders' equity
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Current liabilities
|
|
$
|
75,441
|
|
|
$
|
289,930
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
365,371
|
|
Long-term debt
|
|
1,446,535
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,446,535
|
|
|||||
Deferred income taxes
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Other long-term liabilities
|
|
271
|
|
|
34,715
|
|
|
—
|
|
|
—
|
|
|
34,986
|
|
|||||
Payable to parent
|
|
—
|
|
|
2,058,683
|
|
|
—
|
|
|
(2,058,683
|
)
|
|
—
|
|
|||||
Total shareholders' equity
|
|
510,004
|
|
|
(367,737
|
)
|
|
55,985
|
|
|
311,752
|
|
|
510,004
|
|
|||||
Total liabilities and shareholders' equity
|
|
$
|
2,032,251
|
|
|
$
|
2,015,591
|
|
|
$
|
55,985
|
|
|
$
|
(1,746,931
|
)
|
|
$
|
2,356,896
|
|
(in thousands)
|
|
Resources
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Assets
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Current assets:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash and cash equivalents
|
|
$
|
81,840
|
|
|
$
|
(35,892
|
)
|
|
$
|
4,535
|
|
|
$
|
—
|
|
|
$
|
50,483
|
|
Restricted cash
|
|
—
|
|
|
20,570
|
|
|
—
|
|
|
—
|
|
|
20,570
|
|
|||||
Other current assets
|
|
22,533
|
|
|
206,708
|
|
|
5,560
|
|
|
—
|
|
|
234,801
|
|
|||||
Total current assets
|
|
104,373
|
|
|
191,386
|
|
|
10,095
|
|
|
—
|
|
|
305,854
|
|
|||||
Equity investments
|
|
—
|
|
|
—
|
|
|
57,562
|
|
|
—
|
|
|
57,562
|
|
|||||
Oil and natural gas properties (full cost accounting method):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Unproved oil and natural gas properties and development costs not being amortized
|
|
6,758
|
|
|
415,290
|
|
|
3,259
|
|
|
—
|
|
|
425,307
|
|
|||||
Proved developed and undeveloped oil and natural gas properties
|
|
337,972
|
|
|
3,097,335
|
|
|
118,903
|
|
|
—
|
|
|
3,554,210
|
|
|||||
Accumulated depletion
|
|
(330,086
|
)
|
|
(1,840,332
|
)
|
|
(13,046
|
)
|
|
—
|
|
|
(2,183,464
|
)
|
|||||
Oil and natural gas properties, net
|
|
14,644
|
|
|
1,672,293
|
|
|
109,116
|
|
|
—
|
|
|
1,796,053
|
|
|||||
Gathering, office, field and other assets, net
|
|
3,481
|
|
|
24,639
|
|
|
22,248
|
|
|
—
|
|
|
50,368
|
|
|||||
Investments in and advances to affiliates, net
|
|
1,834,197
|
|
|
—
|
|
|
—
|
|
|
(1,834,197
|
)
|
|
—
|
|
|||||
Deferred financing costs, net
|
|
27,771
|
|
|
—
|
|
|
1,036
|
|
|
—
|
|
|
28,807
|
|
|||||
Derivative financial instruments
|
|
6,829
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6,829
|
|
|||||
Goodwill
|
|
13,293
|
|
|
149,862
|
|
|
—
|
|
|
—
|
|
|
163,155
|
|
|||||
Total assets
|
|
$
|
2,004,588
|
|
|
$
|
2,038,180
|
|
|
$
|
200,057
|
|
|
$
|
(1,834,197
|
)
|
|
$
|
2,408,628
|
|
Liabilities and shareholders' equity
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Current liabilities
|
|
$
|
76,174
|
|
|
$
|
264,485
|
|
|
$
|
8,511
|
|
|
$
|
—
|
|
|
$
|
349,170
|
|
Long-term debt
|
|
1,770,427
|
|
|
—
|
|
|
88,485
|
|
|
—
|
|
|
1,858,912
|
|
|||||
Deferred income taxes
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Other long-term liabilities
|
|
10,082
|
|
|
33,831
|
|
|
8,728
|
|
|
—
|
|
|
52,641
|
|
|||||
Payable to parent
|
|
—
|
|
|
2,230,108
|
|
|
35,777
|
|
|
(2,265,885
|
)
|
|
—
|
|
|||||
Total shareholders' equity
|
|
147,905
|
|
|
(490,244
|
)
|
|
58,556
|
|
|
431,688
|
|
|
147,905
|
|
|||||
Total liabilities and shareholders' equity
|
|
$
|
2,004,588
|
|
|
$
|
2,038,180
|
|
|
$
|
200,057
|
|
|
$
|
(1,834,197
|
)
|
|
$
|
2,408,628
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Resources
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil and natural gas
|
|
$
|
3,649
|
|
|
$
|
614,889
|
|
|
$
|
41,731
|
|
|
$
|
—
|
|
|
$
|
660,269
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil and natural gas production
|
|
394
|
|
|
77,334
|
|
|
16,598
|
|
|
—
|
|
|
94,326
|
|
|||||
Gathering and transportation
|
|
—
|
|
|
97,784
|
|
|
3,790
|
|
|
—
|
|
|
101,574
|
|
|||||
Depletion, depreciation and amortization
|
|
3,174
|
|
|
244,761
|
|
|
15,634
|
|
|
—
|
|
|
263,569
|
|
|||||
Impairment of oil and natural gas properties
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Accretion of discount on asset retirement obligations
|
|
16
|
|
|
2,107
|
|
|
567
|
|
|
—
|
|
|
2,690
|
|
|||||
General and administrative
|
|
(3,342
|
)
|
|
66,686
|
|
|
2,576
|
|
|
—
|
|
|
65,920
|
|
|||||
Other operating items
|
|
(134
|
)
|
|
5,459
|
|
|
(10
|
)
|
|
—
|
|
|
5,315
|
|
|||||
Total costs and expenses
|
|
108
|
|
|
494,131
|
|
|
39,155
|
|
|
—
|
|
|
533,394
|
|
|||||
Operating income
|
|
3,541
|
|
|
120,758
|
|
|
2,576
|
|
|
—
|
|
|
126,875
|
|
|||||
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest expense, net
|
|
(92,049
|
)
|
|
—
|
|
|
(2,235
|
)
|
|
—
|
|
|
(94,284
|
)
|
|||||
Gain on derivative financial instruments
|
|
87,565
|
|
|
—
|
|
|
100
|
|
|
—
|
|
|
87,665
|
|
|||||
Other income
|
|
226
|
|
|
—
|
|
|
15
|
|
|
—
|
|
|
241
|
|
|||||
Equity income
|
|
—
|
|
|
—
|
|
|
172
|
|
|
—
|
|
|
172
|
|
|||||
Net earnings from consolidated subsidiaries
|
|
121,386
|
|
|
—
|
|
|
—
|
|
|
(121,386
|
)
|
|
—
|
|
|||||
Total other income (expense)
|
|
117,128
|
|
|
—
|
|
|
(1,948
|
)
|
|
(121,386
|
)
|
|
(6,206
|
)
|
|||||
Income before income taxes
|
|
120,669
|
|
|
120,758
|
|
|
628
|
|
|
(121,386
|
)
|
|
120,669
|
|
|||||
Income tax expense
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Net income
|
|
$
|
120,669
|
|
|
$
|
120,758
|
|
|
$
|
628
|
|
|
$
|
(121,386
|
)
|
|
$
|
120,669
|
|
(in thousands)
|
|
Resources
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil and natural gas
|
|
$
|
9,136
|
|
|
$
|
582,158
|
|
|
$
|
43,015
|
|
|
$
|
—
|
|
|
$
|
634,309
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil and natural gas production
|
|
2,440
|
|
|
63,716
|
|
|
17,092
|
|
|
—
|
|
|
83,248
|
|
|||||
Gathering and transportation
|
|
—
|
|
|
97,166
|
|
|
3,479
|
|
|
—
|
|
|
100,645
|
|
|||||
Depletion, depreciation and amortization
|
|
5,917
|
|
|
225,499
|
|
|
14,359
|
|
|
—
|
|
|
245,775
|
|
|||||
Impairment of oil and natural gas properties
|
|
—
|
|
|
108,546
|
|
|
—
|
|
|
—
|
|
|
108,546
|
|
|||||
Accretion of discount on asset retirement obligations
|
|
63
|
|
|
1,881
|
|
|
570
|
|
|
—
|
|
|
2,514
|
|
|||||
General and administrative
|
|
23,125
|
|
|
66,558
|
|
|
2,195
|
|
|
—
|
|
|
91,878
|
|
|||||
Gain on divestitures and other operating items
|
|
(25,950
|
)
|
|
(151,549
|
)
|
|
(19
|
)
|
|
—
|
|
|
(177,518
|
)
|
|||||
Total costs and expenses
|
|
5,595
|
|
|
411,817
|
|
|
37,676
|
|
|
—
|
|
|
455,088
|
|
|||||
Operating income (loss)
|
|
3,541
|
|
|
170,341
|
|
|
5,339
|
|
|
—
|
|
|
179,221
|
|
|||||
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest expense, net
|
|
(99,815
|
)
|
|
—
|
|
|
(2,774
|
)
|
|
—
|
|
|
(102,589
|
)
|
|||||
Gain (loss) on derivative financial instruments
|
|
1,439
|
|
|
(177
|
)
|
|
(1,582
|
)
|
|
—
|
|
|
(320
|
)
|
|||||
Other income (loss)
|
|
(1,068
|
)
|
|
229
|
|
|
11
|
|
|
—
|
|
|
(828
|
)
|
|||||
Equity loss
|
|
—
|
|
|
—
|
|
|
(53,280
|
)
|
|
—
|
|
|
(53,280
|
)
|
|||||
Net earnings from consolidated subsidiaries
|
|
118,107
|
|
|
—
|
|
|
—
|
|
|
(118,107
|
)
|
|
—
|
|
|||||
Total other income (expense)
|
|
18,663
|
|
|
52
|
|
|
(57,625
|
)
|
|
(118,107
|
)
|
|
(157,017
|
)
|
|||||
Income (loss) before income taxes
|
|
22,204
|
|
|
170,393
|
|
|
(52,286
|
)
|
|
(118,107
|
)
|
|
22,204
|
|
|||||
Income tax expense
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Net income (loss)
|
|
$
|
22,204
|
|
|
$
|
170,393
|
|
|
$
|
(52,286
|
)
|
|
$
|
(118,107
|
)
|
|
$
|
22,204
|
|
(in thousands)
|
|
Resources
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil and natural gas
|
|
$
|
78,649
|
|
|
$
|
467,960
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
546,609
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil and natural gas production
|
|
19,820
|
|
|
84,790
|
|
|
—
|
|
|
—
|
|
|
104,610
|
|
|||||
Gathering and transportation
|
|
—
|
|
|
102,875
|
|
|
—
|
|
|
—
|
|
|
102,875
|
|
|||||
Depletion, depreciation and amortization
|
|
7,767
|
|
|
295,389
|
|
|
—
|
|
|
—
|
|
|
303,156
|
|
|||||
Impairment of oil and natural gas properties
|
|
—
|
|
|
1,346,749
|
|
|
—
|
|
|
—
|
|
|
1,346,749
|
|
|||||
Accretion of discount on asset retirement obligations
|
|
526
|
|
|
3,361
|
|
|
—
|
|
|
—
|
|
|
3,887
|
|
|||||
General and administrative
|
|
14,394
|
|
|
69,424
|
|
|
—
|
|
|
—
|
|
|
83,818
|
|
|||||
Other operating items
|
|
(194
|
)
|
|
17,223
|
|
|
—
|
|
|
—
|
|
|
17,029
|
|
|||||
Total costs and expenses
|
|
42,313
|
|
|
1,919,811
|
|
|
—
|
|
|
—
|
|
|
1,962,124
|
|
|||||
Operating income (loss)
|
|
36,336
|
|
|
(1,451,851
|
)
|
|
—
|
|
|
—
|
|
|
(1,415,515
|
)
|
|||||
Other income:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest expense, net
|
|
(73,489
|
)
|
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
(73,492
|
)
|
|||||
Gain on derivative financial instruments
|
|
62,812
|
|
|
3,321
|
|
|
—
|
|
|
—
|
|
|
66,133
|
|
|||||
Other income
|
|
238
|
|
|
731
|
|
|
—
|
|
|
—
|
|
|
969
|
|
|||||
Equity income
|
|
—
|
|
|
—
|
|
|
28,620
|
|
|
—
|
|
|
28,620
|
|
|||||
Net loss from consolidated subsidiaries
|
|
(1,419,182
|
)
|
|
—
|
|
|
—
|
|
|
1,419,182
|
|
|
—
|
|
|||||
Total other income (expense)
|
|
(1,429,621
|
)
|
|
4,049
|
|
|
28,620
|
|
|
1,419,182
|
|
|
22,230
|
|
|||||
Income (loss) before income taxes
|
|
(1,393,285
|
)
|
|
(1,447,802
|
)
|
|
28,620
|
|
|
1,419,182
|
|
|
(1,393,285
|
)
|
|||||
Income tax expense
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Net income (loss)
|
|
$
|
(1,393,285
|
)
|
|
$
|
(1,447,802
|
)
|
|
$
|
28,620
|
|
|
$
|
1,419,182
|
|
|
$
|
(1,393,285
|
)
|
(in thousands)
|
|
Resources
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Operating Activities:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash provided by (used in) operating activities
|
|
$
|
(84,067
|
)
|
|
$
|
428,029
|
|
|
$
|
18,131
|
|
|
$
|
—
|
|
|
$
|
362,093
|
|
Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions
|
|
(2,531
|
)
|
|
(395,974
|
)
|
|
(4,061
|
)
|
|
—
|
|
|
(402,566
|
)
|
|||||
Restricted cash
|
|
—
|
|
|
(3,400
|
)
|
|
—
|
|
|
—
|
|
|
(3,400
|
)
|
|||||
Equity method investments
|
|
—
|
|
|
1,749
|
|
|
—
|
|
|
—
|
|
|
1,749
|
|
|||||
Proceeds from disposition of property and equipment
|
|
99,612
|
|
|
95,594
|
|
|
(7,551
|
)
|
|
—
|
|
|
187,655
|
|
|||||
Distributions received from Compass
|
|
5,856
|
|
|
—
|
|
|
—
|
|
|
(5,856
|
)
|
|
—
|
|
|||||
Net changes in advances to joint ventures
|
|
—
|
|
|
(5,026
|
)
|
|
—
|
|
|
—
|
|
|
(5,026
|
)
|
|||||
Advances/investments with affiliates
|
|
125,612
|
|
|
(125,612
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Net cash provided by (used in) investing activities
|
|
228,549
|
|
|
(432,669
|
)
|
|
(11,612
|
)
|
|
(5,856
|
)
|
|
(221,588
|
)
|
|||||
Financing Activities:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Borrowings under credit agreements
|
|
100,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
100,000
|
|
|||||
Repayments under credit agreements
|
|
(959,874
|
)
|
|
—
|
|
|
(5,096
|
)
|
|
—
|
|
|
(964,970
|
)
|
|||||
Proceeds received from issuance of 2022 Notes
|
|
500,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
500,000
|
|
|||||
Proceeds from issuance of common shares, net
|
|
271,773
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
271,773
|
|
|||||
Payment of common share dividends
|
|
(41,060
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(41,060
|
)
|
|||||
Compass cash distribution
|
|
—
|
|
|
—
|
|
|
(5,856
|
)
|
|
5,856
|
|
|
—
|
|
|||||
Deferred financing costs and other
|
|
(10,188
|
)
|
|
—
|
|
|
(102
|
)
|
|
—
|
|
|
(10,290
|
)
|
|||||
Payments of common shares repurchased
|
|
(136
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(136
|
)
|
|||||
Net cash used in financing activities
|
|
(139,485
|
)
|
|
—
|
|
|
(11,054
|
)
|
|
5,856
|
|
|
(144,683
|
)
|
|||||
Net increase (decrease) in cash
|
|
4,997
|
|
|
(4,640
|
)
|
|
(4,535
|
)
|
|
—
|
|
|
(4,178
|
)
|
|||||
Cash at beginning of period
|
|
81,840
|
|
|
(35,892
|
)
|
|
4,535
|
|
|
—
|
|
|
50,483
|
|
|||||
Cash at end of period
|
|
$
|
86,837
|
|
|
$
|
(40,532
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
46,305
|
|
(in thousands)
|
|
Resources
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Operating Activities:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash provided by (used in) operating activities
|
|
$
|
(32,678
|
)
|
|
$
|
365,770
|
|
|
$
|
17,542
|
|
|
$
|
—
|
|
|
$
|
350,634
|
|
Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions
|
|
(15,767
|
)
|
|
(1,242,667
|
)
|
|
(38,818
|
)
|
|
—
|
|
|
(1,297,252
|
)
|
|||||
Restricted cash
|
|
—
|
|
|
49,515
|
|
|
—
|
|
|
—
|
|
|
49,515
|
|
|||||
Equity method investments
|
|
—
|
|
|
236,289
|
|
|
—
|
|
|
—
|
|
|
236,289
|
|
|||||
Proceeds from disposition of property and equipment
|
|
244,500
|
|
|
505,128
|
|
|
—
|
|
|
—
|
|
|
749,628
|
|
|||||
Distributions from Compass
|
|
3,825
|
|
|
—
|
|
|
—
|
|
|
(3,825
|
)
|
|
—
|
|
|||||
Net changes in advances to joint ventures
|
|
—
|
|
|
10,645
|
|
|
—
|
|
|
—
|
|
|
10,645
|
|
|||||
Advances/investments with affiliates
|
|
(59,575
|
)
|
|
59,575
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Other
|
|
(1,303
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,303
|
)
|
|||||
Net cash provided by (used in) investing activities
|
|
171,680
|
|
|
(381,515
|
)
|
|
(38,818
|
)
|
|
(3,825
|
)
|
|
(252,478
|
)
|
|||||
Financing Activities:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Borrowings under credit agreements
|
|
967,766
|
|
|
—
|
|
|
36,757
|
|
|
—
|
|
|
1,004,523
|
|
|||||
Repayments under credit agreements
|
|
(1,015,900
|
)
|
|
—
|
|
|
(6,885
|
)
|
|
—
|
|
|
(1,022,785
|
)
|
|||||
Proceeds from issuance of common shares, net
|
|
1,712
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,712
|
|
|||||
Payment of common share dividends
|
|
(43,214
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(43,214
|
)
|
|||||
Compass cash distribution
|
|
—
|
|
|
—
|
|
|
(3,825
|
)
|
|
3,825
|
|
|
—
|
|
|||||
Deferred financing costs and other
|
|
(33,317
|
)
|
|
—
|
|
|
(236
|
)
|
|
—
|
|
|
(33,553
|
)
|
|||||
Net cash provided by (used in) financing activities
|
|
(122,953
|
)
|
|
—
|
|
|
25,811
|
|
|
3,825
|
|
|
(93,317
|
)
|
|||||
Net increase (decrease) in cash
|
|
16,049
|
|
|
(15,745
|
)
|
|
4,535
|
|
|
—
|
|
|
4,839
|
|
|||||
Cash at beginning of period
|
|
65,791
|
|
|
(20,147
|
)
|
|
—
|
|
|
—
|
|
|
45,644
|
|
|||||
Cash at end of period
|
|
$
|
81,840
|
|
|
$
|
(35,892
|
)
|
|
$
|
4,535
|
|
|
$
|
—
|
|
|
$
|
50,483
|
|
(in thousands)
|
|
Resources
|
|
Guarantor Subsidiaries
|
|
Non-guarantor subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Operating Activities:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash provided by operating activities
|
|
$
|
182,143
|
|
|
$
|
332,643
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
514,786
|
|
Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Additions to oil and natural gas properties, gathering assets and equipment
|
|
(77,006
|
)
|
|
(459,917
|
)
|
|
—
|
|
|
—
|
|
|
(536,923
|
)
|
|||||
Restricted cash
|
|
—
|
|
|
85,840
|
|
|
—
|
|
|
—
|
|
|
85,840
|
|
|||||
Equity method investments
|
|
—
|
|
|
(14,907
|
)
|
|
—
|
|
|
—
|
|
|
(14,907
|
)
|
|||||
Proceeds from disposition of property and equipment
|
|
15,161
|
|
|
22,884
|
|
|
—
|
|
|
—
|
|
|
38,045
|
|
|||||
Net changes in advances to joint ventures
|
|
—
|
|
|
851
|
|
|
—
|
|
|
—
|
|
|
851
|
|
|||||
Advances/investments with affiliates
|
|
(59,126
|
)
|
|
59,126
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Net cash used in investing activities
|
|
(120,971
|
)
|
|
(306,123
|
)
|
|
—
|
|
|
—
|
|
|
(427,094
|
)
|
|||||
Financing Activities:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Borrowings under the credit agreements
|
|
53,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
53,000
|
|
|||||
Repayments under the credit agreements
|
|
(93,000
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(93,000
|
)
|
|||||
Proceeds from issuance of common shares, net
|
|
1,968
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,968
|
|
|||||
Payment of common share dividends
|
|
(34,358
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(34,358
|
)
|
|||||
Deferred financing costs and other
|
|
(1,655
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,655
|
)
|
|||||
Net cash used in financing activities
|
|
(74,045
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(74,045
|
)
|
|||||
Net increase (decrease) in cash
|
|
(12,873
|
)
|
|
26,520
|
|
|
—
|
|
|
—
|
|
|
13,647
|
|
|||||
Cash at beginning of period
|
|
78,664
|
|
|
(46,667
|
)
|
|
—
|
|
|
—
|
|
|
31,997
|
|
|||||
Cash at end of period
|
|
$
|
65,791
|
|
|
$
|
(20,147
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
45,644
|
|
17.
|
Quarterly financial data (unaudited)
|
|
|
Quarter
|
||||||||||||||
(in thousands, except per share amounts)
|
|
1st
|
|
2nd
|
|
3rd
|
|
4th
|
||||||||
2014
|
|
|
|
|
|
|
|
|
||||||||
Oil and natural gas revenues
|
|
$
|
198,472
|
|
|
$
|
182,966
|
|
|
$
|
151,042
|
|
|
$
|
127,789
|
|
Operating income (loss)
|
|
57,423
|
|
|
43,312
|
|
|
22,799
|
|
|
3,341
|
|
||||
Net income (loss)
|
|
$
|
(4,606
|
)
|
|
$
|
2,293
|
|
|
$
|
41,569
|
|
|
$
|
81,413
|
|
Basic earnings (loss) per share:
|
|
|
|
|
|
|
|
|
||||||||
Net income (loss)
|
|
$
|
(0.02
|
)
|
|
$
|
0.01
|
|
|
$
|
0.15
|
|
|
$
|
0.30
|
|
Weighted average shares
|
|
260,716
|
|
|
270,492
|
|
|
270,631
|
|
|
271,053
|
|
||||
Diluted earnings (loss) per share:
|
|
|
|
|
|
|
|
|
||||||||
Net income (loss)
|
|
$
|
(0.02
|
)
|
|
$
|
0.01
|
|
|
$
|
0.15
|
|
|
$
|
0.30
|
|
Weighted average shares
|
|
260,716
|
|
|
271,226
|
|
|
272,066
|
|
|
271,053
|
|
||||
|
|
|
|
|
|
|
|
|
||||||||
2013
|
|
|
|
|
|
|
|
|
||||||||
Oil and natural gas revenues
|
|
$
|
138,223
|
|
|
$
|
150,332
|
|
|
$
|
165,314
|
|
|
$
|
180,440
|
|
Operating income (loss) (1)
|
|
209,075
|
|
|
33,883
|
|
|
15,594
|
|
|
(79,331
|
)
|
||||
Net income (loss) (2) (3)
|
|
$
|
158,120
|
|
|
$
|
85,598
|
|
|
$
|
(98,651
|
)
|
|
$
|
(122,863
|
)
|
Basic earnings (loss) per share:
|
|
|
|
|
|
|
|
|
||||||||
Net income (loss)
|
|
$
|
0.74
|
|
|
$
|
0.40
|
|
|
$
|
(0.46
|
)
|
|
$
|
(0.57
|
)
|
Weighted average shares
|
|
214,784
|
|
|
214,788
|
|
|
215,056
|
|
|
215,410
|
|
||||
Diluted earnings (loss) per share:
|
|
|
|
|
|
|
|
|
||||||||
Net income (loss)
|
|
$
|
0.74
|
|
|
$
|
0.40
|
|
|
$
|
(0.46
|
)
|
|
$
|
(0.57
|
)
|
Weighted average shares
|
|
214,861
|
|
|
216,023
|
|
|
215,056
|
|
|
215,410
|
|
(1)
|
Operating income (loss) for the first quarter and the fourth quarter of 2013 includes
$10.7 million
and
$97.8 million
, respectively, of impairments of oil and natural gas properties. See "Note 2. Summary of significant accounting policies" for further discussion.
|
(2)
|
Net income (loss) for the third quarter of 2013 includes a
$91.5 million
impairment to our investment in TGGT as a result of the carrying value exceeding the fair value. The impairment was reduced by
$4.7 million
in the fourth quarter of 2013 to
$86.8 million
as a result of final closing adjustments, fees and transaction expenses related to the sale of our equity investment in TGGT. See "Note 3. Acquisitions, divestitures and other significant events" for further discussion.
|
(3)
|
Net income (loss) for the first quarter of 2013 includes a gain of
$187.0 million
from our contribution of oil and natural gas properties to Compass. See "Note 3. Acquisitions, divestitures and other significant events" for further discussion.
|
18.
|
Supplemental information relating to oil and natural gas producing activities (unaudited)
|
(in thousands, except per unit amounts)
|
|
Amount
|
||
2014:
|
|
|
||
Proved property acquisition costs
|
|
$
|
10,562
|
|
Unproved property acquisition costs
|
|
—
|
|
|
Total property acquisition costs
|
|
10,562
|
|
|
Development
|
|
354,199
|
|
|
Exploration costs (1)
|
|
5,906
|
|
|
Lease acquisitions and other
|
|
9,681
|
|
|
Capitalized asset retirement costs
|
|
576
|
|
|
Depletion per Boe
|
|
$
|
11.42
|
|
Depletion per Mcfe
|
|
$
|
1.90
|
|
2013:
|
|
|
||
Proved property acquisition costs
|
|
$
|
754,370
|
|
Unproved property acquisition costs
|
|
232,020
|
|
|
Total property acquisition costs (2)
|
|
986,390
|
|
|
Development
|
|
231,447
|
|
|
Exploration costs (3)
|
|
38,579
|
|
|
Lease acquisitions and other
|
|
14,835
|
|
|
Capitalized asset retirement costs
|
|
514
|
|
|
Depletion per Boe
|
|
$
|
8.82
|
|
Depletion per Mcfe
|
|
$
|
1.47
|
|
2012:
|
|
|
||
Proved property acquisition costs
|
|
$
|
—
|
|
Unproved property acquisition costs
|
|
3,349
|
|
|
Total property acquisition costs
|
|
3,349
|
|
|
Development
|
|
346,017
|
|
|
Exploration costs (4)
|
|
57,325
|
|
|
Lease acquisitions and other (5)
|
|
44,546
|
|
|
Capitalized asset retirement costs
|
|
971
|
|
|
Depletion per Boe
|
|
$
|
9.11
|
|
Depletion per Mcfe
|
|
$
|
1.52
|
|
(1)
|
Exploration costs in 2014 include
$5.9 million
in the Bossier shale in North Louisiana.
|
(2)
|
Acquisition costs in 2013 include the acquisition of properties in the Haynesville and Eagle Ford shales and our proportionate share of Compass's acquisition of shallow Cotton Valley assets.
|
(3)
|
Exploration costs in 2013 include
$29.2 million
in the Eagle Ford shale and
$9.4 million
in the Marcellus shale.
|
(4)
|
Exploration costs in 2012 include
$40.1 million
in the Haynesville shale
$17.2 million
in the Marcellus shale.
|
(5)
|
Lease acquisition costs in 2012 are net of acreage reimbursements from BG Group totaling
$2.1 million
.
|
|
|
Oil
(Mbbls) |
|
Natural
Gas (Mmcf) |
|
Natural Gas Liquids (Mbbls)
|
|
Mmcfe (11)
|
||||
December 31, 2011
|
|
6,354
|
|
|
1,291,464
|
|
|
—
|
|
|
1,329,588
|
|
Purchase of reserves in place
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Discoveries and extensions (1)
|
|
492
|
|
|
96,615
|
|
|
424
|
|
|
102,111
|
|
Revisions of previous estimates:
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in price
|
|
(110
|
)
|
|
(466,238
|
)
|
|
—
|
|
|
(466,898
|
)
|
Other factors (2)
|
|
(463
|
)
|
|
199,784
|
|
|
6,724
|
|
|
237,350
|
|
Sales of reserves in place
|
|
—
|
|
|
(2,837
|
)
|
|
—
|
|
|
(2,837
|
)
|
Production
|
|
(703
|
)
|
|
(182,656
|
)
|
|
(509
|
)
|
|
(189,928
|
)
|
December 31, 2012
|
|
5,570
|
|
|
936,132
|
|
|
6,639
|
|
|
1,009,386
|
|
Purchase of reserves in place (3)
|
|
16,022
|
|
|
290,933
|
|
|
2,201
|
|
|
400,271
|
|
Discoveries and extensions (4)
|
|
5,960
|
|
|
46,834
|
|
|
513
|
|
|
85,672
|
|
Revisions of previous estimates:
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in price
|
|
457
|
|
|
272,614
|
|
|
686
|
|
|
279,472
|
|
Other factors (5)
|
|
(3,219
|
)
|
|
(106,695
|
)
|
|
(741
|
)
|
|
(130,455
|
)
|
Sales of reserves in place (6)
|
|
(8,224
|
)
|
|
(270,018
|
)
|
|
(6,472
|
)
|
|
(358,194
|
)
|
Production
|
|
(1,188
|
)
|
|
(153,321
|
)
|
|
(243
|
)
|
|
(161,907
|
)
|
December 31, 2013
|
|
15,378
|
|
|
1,016,479
|
|
|
2,583
|
|
|
1,124,245
|
|
Purchase of reserves in place (7)
|
|
—
|
|
|
7,316
|
|
|
—
|
|
|
7,316
|
|
Discoveries and extensions (8)
|
|
4,164
|
|
|
69,902
|
|
|
107
|
|
|
95,528
|
|
Revisions of previous estimates:
|
|
|
|
|
|
|
|
|
||||
Changes in price
|
|
45
|
|
|
167,302
|
|
|
127
|
|
|
168,334
|
|
Other factors (9)
|
|
1,737
|
|
|
120,850
|
|
|
(8
|
)
|
|
131,224
|
|
Sales of reserves in place (10)
|
|
(1,401
|
)
|
|
(105,841
|
)
|
|
(2,144
|
)
|
|
(127,111
|
)
|
Production
|
|
(2,236
|
)
|
|
(120,980
|
)
|
|
(224
|
)
|
|
(135,740
|
)
|
December 31, 2014
|
|
17,687
|
|
|
1,155,028
|
|
|
441
|
|
|
1,263,796
|
|
|
|
Oil
(Mbbls) |
|
Natural
Gas (Mmcf) |
|
Natural Gas Liquids (Mbbls)
|
|
Mmcfe
|
||||
Proved developed:
|
|
|
|
|
|
|
|
|
||||
December 31, 2014
|
|
14,429
|
|
|
502,314
|
|
|
387
|
|
|
591,210
|
|
December 31, 2013
|
|
11,274
|
|
|
657,116
|
|
|
2,088
|
|
|
737,291
|
|
December 31, 2012
|
|
4,371
|
|
|
917,326
|
|
|
4,784
|
|
|
972,256
|
|
Proved undeveloped:
|
|
|
|
|
|
|
|
|
||||
December 31, 2014
|
|
3,258
|
|
|
652,714
|
|
|
54
|
|
|
672,586
|
|
December 31, 2013
|
|
4,104
|
|
|
359,363
|
|
|
495
|
|
|
386,954
|
|
December 31, 2012
|
|
1,199
|
|
|
18,806
|
|
|
1,855
|
|
|
37,130
|
|
(1)
|
New discoveries and extensions in 2012 include
25,626
Mmcfe in East Texas/North Louisiana, primarily in the Haynesville shale,
59,455
Mmcfe in the Marcellus shale and
17,027
Mmcfe in the Permian Basin.
|
(2)
|
Total revisions due to Other factors in 2012 include approximately
8,736
Mmcfe of Proved Undeveloped Reserves that were reclassified to unproved reserves as a result of a slower development schedule due to depressed natural gas prices,
|
(3)
|
Purchases of reserves in place include
115,718
Mmcfe in the Eagle Ford shale,
259,991
Mmcfe in the Haynesville shale, and
24,558
Mmcfe for our proportionate share of Compass's acquisition of shallow Cotton Valley assets in East Texas/North Louisiana.
|
(4)
|
New discoveries and extensions in 2013 include
36,501
Mmcfe in the Eagle Ford shale,
33,591
Mmcfe in the Marcellus shale,
10,211
Mmcfe in the Haynesville shale,
3,881
Mmcfe for conventional properties held by Compass in the Permian Basin, and
1,486
Mmcfe for shale properties in the Permian Basin.
|
(5)
|
Total revisions due to Other factors were downward revisions primarily in the Haynesville shale as a result of operational matters including scaling, liquid loading due to high-line pressure and the impact of drainage on new wells drilled directly offset to the unit wells.
|
(6)
|
Sales of reserves in place in 2013 include
327,608
Mmcfe as a result of our contribution of properties to Compass and
30,582
Mmcfe from the sale of undeveloped properties in the Eagle Ford in connection with the Participation Agreement.
|
(7)
|
Purchases of reserves in place in 2014 consist primarily of our acquisition of certain proved developed producing properties in the Shelby area of East Texas.
|
(8)
|
New discoveries and extensions in 2014 included
48,698
Mmcfe in the Haynesville shale,
26,148
Mmcfe in the Eagle Ford Shale and
19,664
in the Bossier shale. The discoveries and extensions within the Haynesville and Bossier shales primarily related to our development of properties within the Shelby area of East Texas.
|
(9)
|
Total revisions due to Other factors include upward revisions of approximately
67,095
Mmcfe in the Shelby area, approximately
45,878
Mmcfe in the Appalachia region, and approximately
5,836
Mmcfe in the Holly area. The upward revisions were primarily due to improved well performance resulting from enhanced well designs and completion techniques.
|
(10)
|
Sales of reserves in place in 2014 consist primarily of the sale of our entire interest in Compass.
|
(11)
|
The above reserves do not include our equity interest in OPCO, which was not significant in any period presented.
|
(in thousands)
|
|
Amount
|
||
Year ended December 31, 2014:
|
|
|
||
Future cash inflows
|
|
$
|
6,097,207
|
|
Future production costs
|
|
2,094,796
|
|
|
Future development costs
|
|
1,124,873
|
|
|
Future income taxes
|
|
—
|
|
|
Future net cash flows
|
|
2,877,538
|
|
|
Discount of future net cash flows at 10% per annum
|
|
1,334,951
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
1,542,587
|
|
Year ended December 31, 2013:
|
|
|
|
|
Future cash inflows
|
|
$
|
5,176,030
|
|
Future production costs
|
|
2,207,230
|
|
|
Future development costs
|
|
904,116
|
|
|
Future income taxes
|
|
—
|
|
|
Future net cash flows
|
|
2,064,684
|
|
|
Discount of future net cash flows at 10% per annum
|
|
812,411
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
1,252,273
|
|
Year ended December 31, 2012:
|
|
|
|
|
Future cash inflows
|
|
$
|
3,187,480
|
|
Future production costs
|
|
1,824,702
|
|
|
Future development costs
|
|
266,726
|
|
|
Future income taxes
|
|
—
|
|
|
Future net cash flows
|
|
1,096,052
|
|
|
Discount of future net cash flows at 10% per annum
|
|
399,905
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
696,147
|
|
(in thousands)
|
|
Amount
|
||
Year ended December 31, 2014:
|
|
|
||
Sales and transfers of oil and natural gas produced
|
|
$
|
(464,369
|
)
|
Net changes in prices and production costs
|
|
279,944
|
|
|
Extensions and discoveries, net of future development and production costs
|
|
196,796
|
|
|
Development costs during the period
|
|
189,155
|
|
|
Changes in estimated future development costs
|
|
(254,737
|
)
|
|
Revisions of previous quantity estimates
|
|
412,296
|
|
|
Sales of reserves in place
|
|
(148,226
|
)
|
|
Purchase of reserves in place
|
|
13,507
|
|
|
Accretion of discount before income taxes
|
|
125,227
|
|
|
Changes in timing and other
|
|
(59,279
|
)
|
|
Net change in income taxes
|
|
—
|
|
|
Net change
|
|
$
|
290,314
|
|
Year ended December 31, 2013:
|
|
|
|
|
Sales and transfers of oil and natural gas produced
|
|
$
|
(450,415
|
)
|
Net changes in prices and production costs
|
|
582,725
|
|
|
Extensions and discoveries, net of future development and production costs
|
|
197,223
|
|
|
Development costs during the period
|
|
55,196
|
|
|
Changes in estimated future development costs
|
|
(251,484
|
)
|
|
Revisions of previous quantity estimates
|
|
98,283
|
|
|
Sales of reserves in place
|
|
(315,758
|
)
|
|
Purchase of reserves in place
|
|
604,366
|
|
|
Accretion of discount before income taxes
|
|
69,615
|
|
|
Changes in timing and other
|
|
(33,625
|
)
|
|
Net change in income taxes
|
|
—
|
|
|
Net change
|
|
$
|
556,126
|
|
Year ended December 31, 2012:
|
|
|
|
|
Sales and transfers of oil and natural gas produced
|
|
$
|
(339,125
|
)
|
Net changes in prices and production costs
|
|
(1,258,493
|
)
|
|
Extensions and discoveries, net of future development and production costs
|
|
90,633
|
|
|
Development costs during the period
|
|
204,929
|
|
|
Changes in estimated future development costs
|
|
404,414
|
|
|
Revisions of previous quantity estimates
|
|
(336,142
|
)
|
|
Sales of reserves in place
|
|
(3,604
|
)
|
|
Purchase of reserves in place
|
|
—
|
|
|
Accretion of discount before income taxes
|
|
165,755
|
|
|
Changes in timing and other
|
|
94,129
|
|
|
Net change in income taxes
|
|
247,189
|
|
|
Net change
|
|
$
|
(730,315
|
)
|
(in thousands)
|
|
Total
|
|
2014
|
|
2013
|
|
2012
|
|
2011 and
prior |
||||||||||
Property acquisition costs
|
|
$
|
228,553
|
|
|
$
|
9,737
|
|
|
$
|
71,524
|
|
|
$
|
3,038
|
|
|
$
|
144,254
|
|
Exploration and development
|
|
16,366
|
|
|
10,797
|
|
|
73
|
|
|
524
|
|
|
4,972
|
|
|||||
Capitalized interest
|
|
31,106
|
|
|
11,871
|
|
|
8,737
|
|
|
6,796
|
|
|
3,702
|
|
|||||
Total
|
|
$
|
276,025
|
|
|
$
|
32,405
|
|
|
$
|
80,334
|
|
|
$
|
10,358
|
|
|
$
|
152,928
|
|
Date:
|
February 25, 2015
|
|
EXCO RESOURCES, INC.
|
|
|
|
(Registrant)
|
|
|
EXCO RESOURCES, INC.
|
|
|
|
(Registrant)
|
|
|
|
|
|
Date:
|
February 25, 2015
|
|
/s/ Harold L. Hickey
|
|
|
|
Harold L. Hickey
|
|
|
|
President and Chief Operating Officer
|
|
|
|
|
|
|
|
/s/ Richard A. Burnett
|
|
|
|
Richard A. Burnett
|
|
|
|
Vice President, Chief Financial Officer
|
|
|
|
and Chief Accounting Officer
|
|
|
|
|
|
|
|
/s/ Jeffrey D. Benjamin
|
|
|
|
Jeffrey D. Benjamin
|
|
|
|
Non-Executive Chairman
|
|
|
|
|
|
|
|
/s/ B. James Ford
|
|
|
|
B. James Ford
|
|
|
|
Director
|
|
|
|
|
|
|
|
/s/ Samuel A. Mitchell
|
|
|
|
Samuel A. Mitchell
|
|
|
|
Director
|
|
|
|
|
|
|
|
/s/ Boone Pickens
|
|
|
|
Boone Pickens
|
|
|
|
Director
|
|
|
|
|
|
|
|
/s/ Wilbur L. Ross, Jr.
|
|
|
|
Wilbur L. Ross, Jr.
|
|
|
|
Director
|
|
|
|
|
|
|
|
/s/ Jeffrey S. Serota
|
|
|
|
Jeffrey S. Serota
|
|
|
|
Director
|
|
|
|
|
|
|
|
/s/ Robert L. Stillwell
|
|
|
|
Robert L. Stillwell
|
|
|
|
Director
|
Number
|
Description of Exhibits
|
2.1
|
Haynesville Purchase and Sale Agreement, by and among Chesapeake Louisiana, L.P., Empress, L.L.C., Empress Louisiana Properties, L.P. and EXCO Operating Company, LP, dated July 2, 2013, filed as an Exhibit to EXCO’s Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2013 filed on October 30, 2013 and incorporated by reference herein.
|
2.2
|
Eagle Ford Purchase and Sale Agreement, by and between Chesapeake Exploration, L.L.C. and EXCO Operating Company, LP, dated July 2, 2013, filed as an Exhibit to EXCO’s Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2013 filed on October 30, 2013 and incorporated by reference herein.
|
2.3
|
Contribution Agreement, by and among BG US Gathering Company, LLC, EXCO Operating Company, LP and Azure Midstream Holdings LLC, dated as of October 16, 2013, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated October 16, 2013 and filed on October 22, 2013 and incorporated by reference herein.
|
2.4
|
Purchase Agreement, dated October 6, 2014, by and among EXCO Resources, Inc., a Texas corporation, EXCO Operating Company, LP, a Delaware limited partnership, EXCO Holding MLP, Inc., a Texas corporation, HGI Energy Holdings, LLC, a Delaware limited liability company, Compass Production Services, LLC, a Delaware limited liability company, and Compass Energy Operating, LLC, a Delaware limited liability company, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated October 6, 2014 and filed on October 10, 2014 and incorporated by reference herein.
|
3.1
|
Third Amended and Restated Articles of Incorporation of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated February 8, 2006 and filed on February 14, 2006 and incorporated by reference herein.
|
3.2
|
Articles of Amendment to the Third Amended and Restated Articles of Incorporation of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated August 30, 2007 and filed on September 5, 2007 and incorporated by reference herein.
|
3.3
|
Second Amended and Restated Bylaws of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated March 4, 2009 and filed on March 6, 2009 and incorporated by reference herein.
|
4.1
|
Indenture, dated September 15, 2010, by and between EXCO Resources, Inc. and Wilmington Trust Company, as trustee, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated September 10, 2010 and filed on September 15, 2010 and incorporated by reference herein.
|
4.2
|
First Supplemental Indenture, dated September 15, 2010, by and among EXCO Resources, Inc., certain of its subsidiaries and Wilmington Trust Company, as trustee, including the form of 7.500% Senior Notes due 2018, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated September 10, 2010 and filed on September 15, 2010 and incorporated by reference herein.
|
4.3
|
Second Supplemental Indenture, dated as of February 12, 2013, by and among EXCO Resources, Inc., EXCO/HGI JV Assets, LLC, EXCO Holding MLP, Inc. and Wilmington Trust Company, as trustee, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated February 12, 2013 and filed on February 19, 2013 and incorporated by reference herein.
|
4.4
|
Third Supplemental Indenture, dated April 16, 2014, by and among EXCO Resources, Inc., certain of its subsidiaries and Wilmington Trust Company, as trustee, including the form of 8.500% Senior Notes due 2022, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated April 11, 2014 and filed on April 16, 2014 and incorporated by reference herein.
|
4.5
|
Fourth Supplemental Indenture, dated May 12, 2014, by and among EXCO Resources, Inc., EXCO Land Company, LLC and Wilmington Trust Company, as trustee, filed as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2014 and filed on July 30, 2014 and incorporated by reference herein.
|
4.6
|
Specimen Stock Certificate for EXCO’s common stock, filed as an Exhibit to EXCO’s Registration Statement on Form S-3 (File No. 333-192898), filed on December 17, 2013 and incorporated by reference herein.
|
4.5
|
First Amended and Restated Registration Rights Agreement dated as of December 30, 2005, by and among EXCO Holdings Inc. and the Initial Holders (as defined therein), filed as an Exhibit to EXCO’s Amendment No. 1 to its Registration Statement on Form S-l (File No. 333-129935), filed on January 6, 2006 and incorporated by reference herein.
|
4.6
|
Registration Rights Agreement, dated March 28, 2007, by and among EXCO Resources, Inc. and the other parties thereto with respect to the 7.0% Cumulative Convertible Perpetual Preferred Stock and the Hybrid Preferred Stock, filed as an Exhibit to EXCO’s Current Report on Form 8-K dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.
|
4.7
|
Registration Rights Agreement, dated March 28, 2007, by and among EXCO Resources, Inc. and the other parties thereto with respect to the Hybrid Preferred Stock, filed as an Exhibit to EXCO’s Current Report on Form 8-K dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.
|
4.8
|
Joinder Agreement to Registration Rights Agreement, dated January 17, 2014, by and among EXCO Resources, Inc. and WLR IV Exco AIV One, L.P., WLR IV Exco AIV Two, L.P., WLR IV Exco AIV Three, L.P., WLR IV Exco AIV Four, L.P., WLR IV Exco AIV Five, L.P., WLR IV Exco AIV Six, L.P., WLR Select Co-Investment XCO AIV, L.P., WLR/GS Master Co-Investment XCO AIV, L.P. and WLR IV Parallel ESC, L.P, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated January 17, 2014 and filed on January 21, 2014 and incorporated by reference herein.
|
4.9
|
Joinder Agreement to Registration Rights Agreement, dated January 17, 2014, by and among EXCO Resources, Inc. and Advent Syndicate 780, Clearwater Insurance Company, Northbridge General Insurance Company, Odyssey Reinsurance Company, Clearwater Select Insurance Company, Riverstone Insurance Limited, Zenith Insurance Company and Fairfax Master Trust Fund, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated January 17, 2014 and filed on January 21, 2014 and incorporated by reference herein.
|
10.1
|
Amended and Restated 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated November 14, 2007 and filed on November 16, 2007 and incorporated by reference herein.*
|
10.2
|
Form of Incentive Stock Option Agreement for the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated November 14, 2007 and filed on November 16, 2007 and incorporated by reference herein.*
|
10.3
|
Form of Nonqualified Stock Option Agreement for the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated November 14, 2007 and filed on November 16, 2007 and incorporated by reference herein.*
|
10.4
|
Form of Restricted Stock Award Agreement for the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated August 4, 2011 and filed on August 10, 2011 and incorporated by reference herein.*
|
10.5
|
Form of Performance-Based Restricted Stock Unit Agreement for the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 30, 2014 and filed on July 3, 2014 and incorporated by reference herein.*
|
10.6
|
Fourth Amended and Restated EXCO Resources, Inc. Severance Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 16, 2011 and filed on March 22, 2011 and incorporated by reference herein.*
|
10.7
|
Amended and Restated 2007 Director Plan of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated November 14, 2007 and filed on November 16, 2007 and incorporated by reference herein.*
|
10.8
|
Amendment Number One to the Amended and Restated 2007 Director Plan of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2009 filed on February 24, 2010 and incorporated by reference herein.*
|
10.9
|
Amendment Number Two to the Amended and Restated 2007 Director Plan of EXCO Resources, Inc., effective as of May 22, 2014, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated May 22, 2014 and filed on May 29, 2014 and incorporated by reference herein.*
|
10.10
|
Letter Agreement, dated March 28, 2007, with OCM Principal Opportunities Fund IV, L.P. and OCM EXCO Holdings, LLC, filed as an Exhibit to EXCO’s Form 8-K (File No. 001-32743), dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.
|
10.11
|
Amendment Number One to the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filed as an exhibit to EXCO’s Current Report on Form 8-K, dated June 4, 2009 and filed on June 10, 2009 and incorporated by reference herein.*
|
10.12
|
Amendment Number Two to the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, dated as of October 6, 2011, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated October 6, 2011 and filed on October 7, 2011 and incorporated by reference herein.*
|
10.13
|
Amendment Number Three to the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, dated as of June 11, 2013, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated June 11, 2013 and filed on June 12, 2013 and incorporated by reference herein.*
|
10.14
|
Form of Restricted Stock Award Agreement, filed as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2013 filed on August 7, 2013 and incorporated by reference herein.*
|
10.15
|
Joint Development Agreement, dated August 14, 2009, by and among BG US Production Company, LLC, EXCO Operating Company, LP and EXCO Production Company, LP, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated August 11, 2009 and filed on August 17, 2009 and incorporated by reference herein.
|
10.16
|
Amendment to Joint Development Agreement, dated February 1, 2011, by and among BG US Production Company, LLC and EXCO Operating Company, LP, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2010 filed February 24, 2011 and incorporated by reference herein.
|
10.17
|
Amendment to Joint Development Agreement, dated October 14, 2014, by and among BG US Production Company, LLC and EXCO Operating Company, LP, filed herewith.
|
10.18
|
Joint Development Agreement, dated as of June 1, 2010, by and among EXCO Production Company (PA), LLC, EXCO Production Company (WV), LLC, BG Production Company, (PA), LLC, BG Production Company, (WV), LLC and EXCO Resources (PA), LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.
|
10.19
|
Amendment to Joint Development Agreement, dated February 4, 2011, by and among EXCO Production Company (PA), LLC, EXCO Production Company (WV), LLC, BG Production Company, (PA), LLC, BG Production Company, (WV), LLC and EXCO Resources (PA), LLC, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2010 filed February 24, 2011 and incorporated by reference herein.
|
10.20
|
Amendment to Joint Development Agreement, dated October 14, 2014, by and among EXCO Production Company (PA), LLC, EXCO Production Company (WV), LLC, BG Production Company, (PA), LLC, BG Production Company, (WV), LLC and EXCO Resources (PA), LLC, filed herewith.
|
10.21
|
Second Amended and Restated Limited Liability Company Agreement of EXCO Resources (PA), LLC, dated June 1, 2010, by and among EXCO Holding (PA), Inc., BG US Production Company, LLC and EXCO Resources (PA), LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.
|
10.22
|
Amendment to Second Amended and Restated Limited Liability Company Agreement of EXCO Resources (PA), LLC, dated October 14, 2014, by and among EXCO Holding (PA), Inc., BG US Production Company, LLC and EXCO Resources (PA), LLC, filed herewith.
|
10.23
|
Second Amended and Restated Limited Liability Company Agreement of Appalachia Midstream, LLC, dated June 1, 2010, by and among EXCO Holding (PA), Inc., BG US Production Company, LLC and Appalachia Midstream, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.
|
10.24
|
Amendment to Second Amended and Restated Limited Liability Company Agreement of Appalachia Midstream, LLC (n/k/a EXCO Appalachia Midstream, LLC), dated October 14, 2014, by and among EXCO Holding (PA), Inc., BG US Production Company, LLC and EXCO Appalachia Midstream, LLC, filed herewith.
|
10.25
|
Letter Agreement, dated June 1, 2010 and effective as of May 9, 2010, by and between EXCO Holding (PA), Inc. and BG US Production Company, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.
|
10.26
|
Guaranty, dated May 9, 2010, by BG Energy Holdings Limited in favor of EXCO Holding (PA), Inc., EXCO Production Company (PA), LLC and EXCO Production Company (WV), LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.
|
10.27
|
Performance Guaranty, dated May 9, 2010, by EXCO Resources, Inc. in favor of BG US Production Company, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.
|
10.28
|
Guaranty, dated June 1, 2010, by BG North America, LLC in favor of (i) EXCO Production Company (PA), LLC, EXCO Production Company (WV), LLC and EXCO Resources (PA), LLC; and (ii) EXCO Resources (PA), LLC and EXCO Holding (PA), Inc, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.
|
10.29
|
Guaranty, dated June 1, 2010, by EXCO Resources, Inc., in favor of: (i) BG Production Company (PA), LLC, BG Production Company (WV), LLC and EXCO Resources (PA), LLC; and (ii) EXCO Resources (PA), LLC and BG US Production Company, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.
|
10.30
|
Transition Consulting Agreement, dated February 28, 2013, by and between EXCO Resources, Inc. and Stephen F. Smith, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated February 28, 2013 and filed on March 6, 2013 and incorporated by reference herein.*
|
10.31
|
Amended and Restated Credit Agreement, dated as of July 31, 2013, among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the lender parties thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO's Form 8-K, dated as of August 19, 2013 and filed on August 23, 2013 and incorporated by reference herein.
|
10.32
|
First Amendment to Amended and Restated Credit Agreement, dated as of August 28, 2013, among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the lender parties thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO's Form 8-K, dated as of August 28, 2013 and filed on September 4, 2013 and incorporated by reference herein.
|
10.33
|
Second Amendment to Amended and Restated Credit Agreement, dated as of July 14, 2014, by and among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO's Form 8-K, dated as of July 14, 2014 and filed on July 18, 2014 and incorporated by reference herein.
|
10.34
|
Third Amendment to Amended and Restated Credit Agreement, dated as of October 21, 2014, by and among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated October 21, 2014 and filed on October 27, 2014 and incorporated by reference herein.
|
10.35
|
Fourth Amendment to Amended and Restated Credit Agreement, dated as of February 6, 2015, among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the lender parties thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO's Form 8-K, dated as of February 6, 2015 and filed on February 12, 2015 and incorporated by reference herein.
|
10.36
|
Participation Agreement, dated July 31, 2013, among Admiral A Holding L.P., Admiral B Holding L.P. and EXCO Operating Company, LP, filed as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2013 filed on August 7, 2013 and incorporated by reference herein.
|
10.37
|
Amendment No. 1 to Participation Agreement, dated April 17, 2014, among EXCO Operating Company, LP, Admiral A Holding L.P. and Admiral B Holding L.P., filed as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2014 and filed on July 30, 2014 and incorporated by reference herein.
|
10.38
|
Form of Director Indemnification Agreement, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 10, 2010 and filed on November 12, 2010 and incorporated by reference herein.
|
10.39
|
MVC Letter Agreement, dated November 15, 2013, among BG US Production Company, LLC, BG US Gathering Company, LLC, EXCO Operating Company, LP, Azure Midstream Energy LLC (formerly known as TGGT Holdings, LLC) and TGG Pipeline, Ltd, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 15, 2013 and filed on November 21, 2013 and incorporated by reference herein.
|
10.40
|
Exercise Commitment Letter, dated November 22, 2013, by and among EXCO Resources, Inc., WLR Recovery Fund IV XCO AIV I, L.P., WLR Recovery Fund IV XCO AIV II, L.P., WLR Recovery Fund IV XCO AIV III, L.P., WLR Select Co-Investment XCO AIV, L.P., WLR/GS Master Co-Investment XCO AIV, L.P. and WLR IV Parallel ESC, L.P, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 22, 2013 and filed on November 25, 2013 and incorporated by reference herein.
|
10.41
|
Exercise Commitment Letter, dated November 22, 2013, by and among EXCO Resources, Inc. and Hamblin Watsa Investment Counsel Ltd, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 22, 2013 and filed on November 25, 2013 and incorporated by reference herein.
|
10.42
|
Investment Agreement, dated December 17, 2013, by and among WLR Recovery Fund IV XCO AIV I, L.P., WLR Recovery Fund IV XCO AIV II, L.P., WLR Recovery Fund IV XCO AIV III, L.P., WLR Select Co-Investment XCO AIV, L.P., WLR/GS Master Co-Investment XCO AIV, L.P., WLR IV Parallel ESC, L.P. and EXCO Resources, Inc., filed as an Exhibit to EXCO’s Registration Statement on Form S-3 dated December 17, 2013 and filed on December 17, 2013 and incorporated by reference herein.
|
10.43
|
Investment Agreement, dated December 17, 2013, by and between Hamblin Watsa Investment Counsel Ltd., as representative of several investors, and EXCO Resources, Inc., filed as an Exhibit to EXCO’s Registration Statement on Form S-3 dated December 17, 2013 and filed on December 17, 2013 and incorporated by reference herein.
|
10.44
|
Settlement Agreement and Mutual Release and Waiver of Claims, dated November 20, 2013, by and between EXCO Resources, Inc. and Douglas H. Miller, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 20, 2013 and filed on November 25, 2013 and incorporated by reference herein.*
|
10.45
|
Bonus and Retention Agreement, dated January 17, 2014, by and between William L. Boeing and EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated January 17, 2014 and filed on January 24, 2014 and incorporated by reference herein.*
|
10.46
|
Bonus and Retention Agreement, dated January 17, 2014, by and between Harold L. Hickey and EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated January 17, 2014 and filed on January 24, 2014 and incorporated by reference herein.*
|
10.47
|
Retention Agreement, effective as of September 1, 2014, by and between Richard A. Burnett and EXCO Resources, Inc., filed as an Exhibit to Amendment No. 1 to EXCO's Current Report on Form 8-K/A, dated August 6, 2014 and filed on September 5, 2014 and incorporated by reference herein.*
|
10.48
|
Letter Agreement, dated March 28, 2014, by and among EXCO Resources, Inc. and Ares Corporate Opportunities Fund, L.P., ACOF EXCO L.P, ACOF EXCO 892 Investors, L.P., Ares Corporate Opportunities Fund II, L.P., Ares EXCO, L.P. and Ares EXCO 892 Investors, L.P., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 27, 2014 and filed on April 1, 2014 and incorporated by reference herein.
|
10.49
|
EXCO Resources, Inc. 2014 Management Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated April 21, 2014 and filed on April 25, 2014 and incorporated by reference herein.*
|
10.50
|
Amendment Number One to the EXCO Resources, Inc. Management Incentive Plan, effective as of September 1, 2014, filed as an Exhibit to Amendment No. 1 to EXCO's Current Report on Form 8-K/A, dated August 6, 2014 and filed on September 5, 2014 and incorporated by reference herein.*
|
14.1
|
Code of Ethics for the Chief Executive Officer and Senior Financial Officers, filed as an Exhibit to EXCO's Amendment No. 1 to its Registration Statement on Form S-1 (File No. 333-129935) filed January 6, 2006 and incorporated by reference herein.
|
14.2
|
Code of Business Conduct and Ethics for Directors, Officers and Employees, filed as an Exhibit to EXCO's Amendment No. 1 to its Registration Statement on Form S-1 (File No. 333-129935) filed January 6, 2006 and incorporated by reference herein.
|
14.3
|
Amendment No. 1 to EXCO Resources, Inc. Code of Business Conduct and Ethics for Directors, Officers and Employees, filed as an Exhibit to EXCO's Current Report on Form 8-K (File No. 001-32743), dated November 8, 2006 and filed on November 9, 2006 and incorporated by reference herein.
|
21.1
|
Subsidiaries of registrant, filed herewith.
|
23.1
|
Consent of KPMG LLP, filed herewith.
|
23.2
|
Consent of Lee Keeling and Associates, Inc., filed herewith.
|
23.3
|
Consent of Netherland, Sewell & Associates, Inc., filed herewith.
|
23.4
|
Consent of Ryder Scott Company, L.P., filed herewith.
|
31.1
|
Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Principal Executive Officer of EXCO Resources, Inc., filed herewith.
|
31.2
|
Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Principal Financial Officer of EXCO Resources, Inc., filed herewith.
|
32.1
|
Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Principal Executive Officer and Principal Financial Officer of EXCO Resources, Inc., filed herewith.
|
99.1
|
2014 Report of Lee Keeling and Associates, Inc., filed herewith.
|
99.2
|
2014 Report of Netherland, Sewell & Associates, Inc., filed herewith.
|
99.3
|
2014 Report of Ryder Scott Company, L.P., filed herewith.
|
99.4
|
2014 Report of Lee Keeling and Associates, Inc. (OK) filed herewith.
|
101.INS
|
XBRL Instance Document.
|
101.SCH
|
XBRL Taxonomy Extension Schema Document.
|
101.CAL
|
XBRL Taxonomy Calculation Linkbase Document.
|
101.DEF
|
XBRL Taxonomy Definition Linkbase Document.
|
101.LAB
|
XBRL Taxonomy Label Linkbase Document.
|
101.PRE
|
XBRL Taxonomy Presentation Linkbase Document.
|
*
|
These exhibits are management contracts.
|
1.
|
Definitions and References.
Capitalized terms used in this Amendment and not otherwise defined herein have the meanings given such terms in the JDA. Sections, Articles, Appendices, Exhibits, Schedules and subsections referred to herein refer to such Sections, Articles, Appendices, Exhibits, Schedules and subsections of the JDA unless the context expressly states otherwise.
|
2.
|
JDA Amendment
. The JDA is hereby amended as follows:
|
(a)
|
Section 3.5(b)(iii)
shall be deleted in its entirety and replaced with the following:
|
“(iii)
|
solely with respect to those After Acquired Units for which EXCO or any Affiliate of EXCO
serves as Party Operator under the relevant Joint Development Operating Agreement, upon a change in Control of the ultimate parent company of EXCO (but excluding a change in Control resulting from a management-led buyout of the public share ownership of such Person and the conversion of such Person to a privately-held Person). Party Operator will be required to resign with respect to operatorship of After Acquired Units within ten (10) days from the election of BG to acquire operatorship or to nominate a third party to serve as operator, effective as of the date BG or such third party actually acquires or assumes operatorship. BG’s election to acquire operatorship or to nominate a third party to serve as operator of After
|
(b)
|
Section 3.6(c)
shall be amended by deleting such section in its entirety and replacing it with the following:
|
“(c)
|
Joint Development Operator may be removed under the following circumstances:
|
(i)
|
by the affirmative vote of the Development Parties, other than Joint Development Operator and its Affiliates, holding a majority of the Participating Interest held by such Development Parties: (A) if there is a Change in Control of Joint Development Operator, provided that such vote is taken by the latter of (I) ninety (90) days after such Change in Control, or (II) ninety (90) days following the delivery of notice to such Development Parties of such Change in Control, such notice to be delivered only after the Change in Control has occurred; or (B) for good cause, provided that in the case of removal for good cause, such vote shall not be deemed effective until a written notice has been delivered to Joint Development Operator by another Party detailing the alleged default and Joint Development Operator has failed to cure the default within thirty (30) days from its receipt of the notice or, if the default concerns an operation then being conducted, within forty-eight (48) hours of its receipt of the notice; or
|
(ii)
|
by the affirmative vote of the Development Parties holding a majority of the Participating Interest in the event that Joint Development Operator’s and its Affiliates’ aggregate Participating Interest falls below twelve and a half percent (12.5%), provided that such vote is taken by the latter of (A) ninety (90) days after the decrease in the Participating Interest held by such Joint Development Operator and its Affiliates’ past such threshold has occurred or (B) ninety (90) days following the delivery of notice to such Development Parties of such decrease past such threshold, such notice to be delivered only after such decrease past such threshold has occurred.
|
(c)
|
Section 3.8
shall be deleted in its entirety and replaced with the following:
|
(d)
|
Section 3.10(a)
shall be amended by:
|
“(xiii)
|
within three (3) weeks from the end of each Calendar Quarter, a schedule showing the working interest and net revenue interests (including net working interest, royalty, overriding royalty, etc.) of
|
(xiv)
|
on or before the 15
th
of each month preceding an obligation or expiration month, the monthly lease maintenance calendars (payments, extensions and expirations) with land recommendations;
|
(xv)
|
copies of all raw microseismic and seismic data, including reprocessing and interpretative data, analysis and reports for the East Texas/North Louisiana Area that (A) are in the possession of the Joint Development Operator or Party Operator, as applicable, (B) are not subject to Third Party confidentiality restrictions that have not been waived and (C) have been generated by EXCO or by a Third Party on behalf of the Joint Development Operator or Party Operator;
|
(xvi)
|
geographic information system data and shape files for the East Texas/North Louisiana Area that (A) are in the possession of the Joint Development Operator or Party Operator, as applicable, (B) are not subject to Third Party confidentiality restrictions that have not been waived and (C) have been generated by EXCO or by a Third Party on behalf of the Joint Development Operator or Party Operator, including any data layers or points associated with shape files such as lease expirations, depth severances and competitor drilling locations;
|
(xvii)
|
at the reasonable request of a Participating Party, a copy of general land data (as currently produced or compiled in the general course of business), inclusive of budget projections data, division of interest calculations, quarterly acreage reports or title curative for the East Texas/North Louisiana Area that are in the possession of Joint Development Operator or Party Operator, as applicable, are not subject to Third Party confidentiality restrictions that have not been waived and have been generated by EXCO or by a Third Party on behalf the Joint Development Operator or Party Operator;
|
(xviii)
|
at the reasonable request of a Participating Party that includes the applicable data query or queries, Joint Development Operator shall, within 30 days after receiving such request, provide such Participating Party with the results of specific data queries on Joint Development Operator’s land systems and databases; provided that the result of such queries provided to such Participating Party shall be limited to only those properties in which such Participating Party and Joint Development Operator own an interest under this Agreement.”
|
(e)
|
Section 3.10(b)(iv)
shall be amended by replacing the phrase “for the purpose of conducting HSSE and asset integrity audits” with the phrase “for the purpose of conducting general audit activities, including conducting EHS and asset integrity audits”.
|
(f)
|
Section 3.10(c)
shall be amended by adding the following to the end of the provision:
|
(g)
|
Section 3.10(d)
shall be deleted in its entirety and replaced with the following:
|
“(d)
|
In addition to the other reports to be provided under this Section 3.10 and to the rights of a Development Party to request information under this Agreement or an Applicable Operating Agreement, for so long as EXCO or an Affiliate of EXCO is the Joint Development Operator and BG or an Affiliate of BG is a Development Party, EXCO shall provide employees and contractors of BG or its Affiliates with unrestricted, on-demand, on-site access during regular business hours to EXCO’s (and its Affiliates’) physical land records and electronic land management system (as of the 2014 Amendment Effective Date, such system is Excalibur and the applicable computer terminals accessing such system are located in Dallas, Texas)
for the purposes of manipulating, reviewing and working with land records (including running queries and producing reports and summaries) related to Subject Oil and Gas Assets and Special Shallow Rights Assets owned by BG or its Affiliates. At BG’s cost and expense, EXCO shall cooperate with efforts by BG to remotely access EXCO’s (and its Affiliates’) land data and information to the extent related to such Subject Oil and Gas Assets and Special Shallow Rights Assets. Notwithstanding the foregoing, EXCO shall only be required to provide access to any such electronic land management system to the extent that (i) providing such access would not violate the provisions of any applicable software or other license (if necessary, after reasonable inquiry by EXCO to the licensor seeking permission for such access), (ii) BG obtains any applicable software or other license that may be required in connection with such access (and BG acknowledges that none of EXCO or its Affiliates will be responsible for obtaining any such license for
|
(h)
|
Section 3.10
shall be amended by adding the following subsections (e), (f) and (g):
|
“(e)
|
For so long as EXCO or an Affiliate of EXCO is acting as Joint Development Operator or Party Operator, EXCO (or such Affiliate) shall actively involve BG in operations and activities which support Development Operations, including, without limitation, by providing a representative of BG the opportunity to participate in (or send another available BG representative to) organized pre-scheduled meetings relating to the Subject Oil and Gas Assets (and, if applicable, Special Shallow Rights Assets) and/or Development Operations, including management team meetings, supply-chain meetings, organization or functional meetings, EHS meetings and contractor committee meetings.
|
(f)
|
To assist BG with any asset disposition analysis or efforts relating to its disposition of Subject Oil and Gas Assets (and, if applicable, Special Shallow Rights Assets), for so long as EXCO or an Affiliate of EXCO is Joint Development Operator, EXCO shall, at BG’s sole cost and expense and without any liability of EXCO or its Affiliates whatsoever (except for liabilities arising due to the willful misconduct of EXCO or its Affiliates), provide support services for any such asset disposition analysis or efforts including, without limitation, assisting with data presentation, providing responses to data requests by BG, providing access to records and data for third party due diligence, and gathering data for purchase and sale agreement representation and warranties; provided that no employee of EXCO or its Affiliates shall be required to make any presentations to potential purchasers. BG shall indemnify EXCO and its Affiliates and their respective employees and representatives for any and all claims and liabilities arising out of or related to any services provided pursuant to this Section in connection with any such proposed asset disposition, except for claims arising due to the willful misconduct of EXCO or its Affiliates.
|
(g)
|
To the extent the applicable information has not previously been provided to BG pursuant to a request under this Section 3.10(g) or prior to the 2014 Amendment Effective Date, Joint Development Operator shall deliver to BG, within a reasonable time period, not to exceed ninety (90) days following a request from BG (which date shall be extended if reasonably requested by
|
(i)
|
Section 3.12(a)
shall be amended by deleting the phrase “change in Control of its ultimate parent company,” and replacing it with the phrase “change in Control of its ultimate parent company (but excluding a change in Control resulting from a management-led buyout of the public share ownership of such Person and the conversion of such Person to a privately-held Person),”.
|
(j)
|
Section 3.12(b)
shall be amended by deleting it in its entirety and replacing it with the following:
|
“(b)
|
The allocation of Technical Services Costs by Joint Development Operator to Development Operations, and the incurrence thereof by Joint Development Operator and its Affiliates, shall be equitable and commercially reasonable, and Joint Development Operator shall furnish details of its allocation procedures to a Development Party upon request. The Joint Development Operator shall not be entitled to receive duplicate payments for such Technical Services Costs. All Technical Services Costs chargeable with respect to Development Operations shall be chargeable to the Development Parties on a Calendar Month basis by Joint Development Operator and each Development Party shall pay its Participating Interest share thereof in accordance with Section 2.2. If any third party participates in a Development Operation for which Technical Services Costs are incurred, and such Technical Services Costs are properly chargeable to such third party, Joint Development Operator (or the applicable Party Operator) shall bill such third party for its working interest share of such Technical Services Costs and not pass such share of such costs on to the Development Parties; and any such amounts collected from third parties in connection therewith will be shared by the Development Parties in accordance with their respective Participating Interests (and Joint Development Operator or Party Operator, as applicable, shall credit to each such other Development Party the proportionate share to which such Development Party is entitled with respect to such amount received by such Joint Development Operator or Party Operator).”
|
(k)
|
Section 4.1(p)
shall be amended by deleting it in its entirety and replacing it with the following:
|
“(p)
|
All notices and communications required or permitted to be given under Section 3.10 or Article 4 to the Development Parties or a Party Operator or the members of the Operating Committee shall be sufficient in all respects if given in writing and delivered personally, or sent by bonded overnight courier, or mailed by U.S. Express Mail or by certified or registered United States Mail with all postage fully prepaid, or sent by facsimile transmission (provided any such facsimile transmission is confirmed either orally or by written confirmation), or sent by pdf via e-mail, addressed to the appropriate Party at the address for such Party shown below or at such other address as such Party shall have theretofore designated by written notice delivered to the Party giving such notice:
|
If to EXCO:
|
|
|
EXCO Resources, Inc.
|
12377 Merit Drive, Suite 1700
|
|
Dallas, Texas 75251
|
|
Attention: William L. Boeing, Vice President,
|
|
General Counsel, and Secretary
|
|
Telephone: (214) 368-2084
|
|
Fax: (214) 706-3409
|
|
E-mail: lboeing@EXCOResources.com
|
|
|
|
With a copy to:
|
|
|
|
Attention Harold L. Hickey
|
|
Telephone: (214) 368-2084
|
|
Fax: (214) 368-8754
|
|
E-mail: hhickey@excoresources.com
|
|
|
|
|
|
If to BG:
|
|
|
BG US Production Company, LLC
|
811 Main Street, Suite 3400
|
|
Houston, Texas 77002
|
|
Attention: Roger Coe
|
|
Telephone: (713) 599-4000
|
|
Fax: (713) 599-4250
|
|
E-mail: roger.coe@bg-group.com
|
|
|
|
|
BG US Production Company, LLC
|
811 Main Street, Suite 3400
|
|
Houston, Texas 77002
|
|
Attention: Chris Migura, Principal Counsel
|
|
Telephone: (713) 599-4000
|
|
Fax: (713) 599-4250
|
|
E-mail: chris.migura@bg-group.com
|
|
|
(l)
|
Section 4.1
shall be amended by adding the following subsection (q):
|
“(q)
|
Effective as of the 2014 Amendment Effective Date, at least ten (10) days prior to each meeting of the Operating Committee, Joint Development Operator shall deliver to the Development Parties (i) an organization chart for the organization supporting Joint Development Operator’s activities, (ii) a proposed allocation of employee or Secondee time for Joint Development Operator activities during the upcoming Calendar Quarter, (iii) an assessment of whether the preceding Calendar Quarter’s allocation of employee or Secondee time for Joint Development Operator activities should be modified, and (iv) a general listing of any significant activities performed or to be performed by employees or Secondees during the current Calendar Quarter which are not Development Operations or otherwise conducted for the benefit of both BG and EXCO or the benefit of Affiliates of both of them pursuant to this Agreement
(such as efforts of EXCO or its Affiliates to support new business development or asset dispositions in which BG does not participate; provided, however, that proprietary information of EXCO and/or its Affiliates in which BG or its Affiliates does not also have a proprietary interest shall not be required to be included in such general listings), together with an estimate of the amount of time spent or to be spent by each individual on such activities during such Calendar Quarter. At a meeting of the Operating Committee each Calendar Quarter, Joint Development Operator shall be prepared to explain and discuss how the various operational departments of Joint Development Operator are resourced and whether such allocation of resources should be modified.”
|
(m)
|
Section 4.7
shall be amended by adding the following subsection (g):
|
“(g)
|
Within ten (10) days after the end of each Calendar Month, Joint Development Operator or Party Operator shall provide each Development Party with a list of Development Operations Contracts relating to Development Operations that can reasonably be expected to result in aggregate payment to the counterparty of more than two hundred fifty thousand dollars (US$250,000), together with the status of any negotiations or tender processes relating to any unexecuted Development Operations Contracts as of the end of the Calendar Month.”
|
(n)
|
Section 9.2(a)
shall be amended by adding the following sentence to the end of the subsection:
|
(o)
|
Section 9.2(b)
shall be amended by deleting the phrase “a period of sixty (60) days after receipt of the Offer Notice” and replacing it with the phrase “until the end of the AMI Election Period”.
|
(p)
|
Section 9.2(e)
shall be amended by deleting the phrase “within thirty (30) days of its receipt of the Offer Notice stating that it does not agree with the Acquiring Development Party’s statement of the Cash Value” and replacing it with the phrase “within twenty (20) days of its receipt of the Offer Notice stating that it does not agree with the Acquiring Development Party’s statement of the Cash Value”.
|
(q)
|
Section 9.2
shall be amended by adding the following subsections (k) and (l):
|
“(k)
|
The Development Parties agree to use good faith efforts to keep each other informed of any prospective Acquired Interest being pursued by each Development Party or its Affiliates within the East Texas/North Louisiana Area prior to the time that an Offer Notice is required under Section 9.2(a). Such obligation shall be subject to confidentiality agreements entered into with third parties; provided that each Development Party shall use its good faith efforts to (i) provide notice of the prospective opportunity prior to entering into any confidentiality agreement and (ii) have an exception included in such agreement allowing disclosure to the other Development Parties and their Affiliates subject to their execution of a substantially similar confidentiality agreement.
|
(l)
|
The area of mutual interest described in Section 9.1 and the applicable area of mutual interest procedures set out in Section 9.2(a) through (k) shall be extended until August 14, 2016, for any Acquired Interest that is located within the Core AMI Area, but only with respect to that portion of any Acquired Interest that is located within such area.”
|
(r)
|
Section 14.2
shall be amended by deleting such section in its entirety and replacing it with the following:
|
If to EXCO:
|
||
|
EXCO Operating Company, LP
|
|
12377 Merit Drive, Suite 1700
|
||
Dallas, Texas 75251
|
||
Attention: President
|
||
Telephone: (214) 368-2084
|
||
Fax: (214) 368-8754
|
||
|
||
With a copy to:
|
||
|
EXCO Operating Company, LP
|
|
12377 Merit Drive, Suite 1700
|
||
Dallas, Texas 75251
|
||
Attention: William L. Boeing, Vice President,
|
||
General Counsel, and Secretary
|
||
Telephone: (214) 368-2084
|
||
Fax: (214) 706-3409
|
||
|
||
If to BG:
|
||
|
BG US Production Company, LLC
|
|
811 Main Street, Suite 3400
|
||
Houston, Texas 77002
|
||
Attention: Roger Coe
|
||
Telephone: (713) 599-4000
|
||
Fax: (713) 599-4250
|
||
|
||
|
with a copy to:
|
|
|
||
BG US Production Company, LLC
|
||
811 Main Street, Suite 3400
|
||
Houston, Texas 77002
|
||
Attention: Chris Migura, Principal Counsel
|
||
Telephone: (713) 599-4000
|
||
Fax: (713) 599-4250
|
||
|
(s)
|
Each use of the term “HSSE” throughout the JDA shall be deleted and replaced with the term “EHS”. The defined terms in
Appendix I
previously beginning with the term “HSSE” and now beginning with the term “EHS” shall be reordered in the appropriate alphabetic locations.
|
(t)
|
Appendix I shall be amended by deleting the definition for “HSSE” in its entirety.
|
(u)
|
Appendix I
shall be amended by deleting the definition for “Secondee” and replacing it with the following:
|
(v)
|
Appendix I
shall be amended by adding the following definitions in their correct alphabetic locations:
|
(w)
|
The JDA shall be amended by attaching Exhibit “J” attached hereto as Exhibit “J” to the JDA.
|
3.
|
Application of Certain Provisions.
The terms of Sections 13.1, 13.2, 14.1, 14.2, 14.3, 14.4, 14.6, 14.7, 14.8, 14.9, 14.10, 14.11, 14.12(a), 14.13 and 14.14 of the JDA are incorporated herein by reference as if set out in full herein.
|
4.
|
Ratification.
Except as amended herein, the terms and conditions of the JDA shall remain in full force and effect. Any and all references to the JDA shall hereafter refer to the JDA as amended by this Amendment.
|
|
|
EXCO OPERATING COMPANY, LP
|
|
|
By: EXCO Partners OLP GP, LLC,
Its general partner
|
|
|
By:
/s/ WILLIAM L. BOEING
Name: William L. Boeing
Title: Vice President and General Counsel
|
|
|
|
|
|
|
|
|
BG US PRODUCTION COMPANY, LLC
|
|
|
By:
/s/ ROGER COE
Name: Roger Coe
Title: Vice President
|
|
|
|
SOLELY FOR THE PURPOSES OF AMENDMENTS TO SECTION 3.8:
|
|
EXCO RESOURCES (PA), LLC
|
|
|
|
|
|
By:
/s/ WILLIAM L. BOEING
Name: William L. Boeing
Title: Vice President and General Counsel
|
1.
|
Definitions and References.
Capitalized terms used in this Amendment and not otherwise defined herein have the meanings given such terms in the JDA. Sections, Articles, Appendices, Exhibits, Schedules and subsections referred to herein refer to such Sections, Articles, Appendices, Exhibits, Schedules and subsections of the JDA unless the context expressly states otherwise.
|
2.
|
JDA Amendment
. The JDA is hereby amended as follows:
|
(a)
|
Section 3.5
shall be amended by adding the following subsection (i):
|
“(i)
|
To the extent the applicable information has not previously been provided to BG pursuant to a request under this Section 3.5(i) or prior to the 2014 Amendment Effective Date, Joint Development Operator shall deliver to BG, within a reasonable time period, not to exceed ninety (90) days following request from BG (which date shall be extended if reasonably requested by Joint Development Operator considering the scope of the request), copies of any files, records, maps, information, and data, whether written or electronically stored, in its possession that relate to Subject Oil and Gas Assets in which BG or an Affiliate of BG holds an interest, including (A)
|
(b)
|
Section 3.6(b)
shall be amended by deleting it in its entirety and replacing it with the following:
|
“(b)
|
The allocation of Technical Services Costs to Development Operations, and the incurrence thereof by a Development Party and its Affiliates, shall be equitable and commercially reasonable, and such Development Party shall furnish details of its allocation procedures to a Development Party upon request. The Development Party providing Technical Services shall not be entitled to receive duplicate payments for such Technical Services Costs.”
|
(c)
|
Section 3.7(c)
shall be amended by deleting it in its entirety and replacing it with the following:
|
“(c)
|
If any Technical Services Costs or overhead chargeable under Article III of Exhibit C to any Joint Development Operating Agreement or any similar provision of any Third Party Operating Agreement are properly chargeable by the Joint Development Operator or any Party Operator to (i) any Participating Party in a Sole Risk Development Operation, (ii) any Development Party, Entity Member or Joint Entity undertaking a Sole Risk Entity Operation, or (iii) any Person other than a Development Party, Entity Member or Joint Entity; then (A) such amounts shall be charged to such applicable Persons and not to any Development Parties, Entity Members or Joint Entities that do not otherwise owe such amounts, and (B) such amounts received by Joint Development Operator or a Party Operator in connection therewith will be shared by the Development Parties in accordance with their respective JDA Interests (and Joint Development Operator or the Party Operator, as applicable, shall credit to each Development Party the proportionate share to which such Development Party is entitled with respect to such amount received by such Joint Development Operator or Party Operator).”
|
(d)
|
Section 4.1(o)
shall be amended by deleting it in its entirety and replacing it with the following:
|
“(o)
|
All notices and communications required or permitted to be given under this Article 4 to the Development Parties or a Party Operator or the members of
|
If to EXCO or any EXCO Member:
|
||
|
EXCO Holding (PA), Inc.
|
|
12377 Merit Drive, Suite 1700
|
||
Dallas, Texas 75251
|
||
Attention: Harold L. Hickey
|
||
Telephone: (214) 368-2084
|
||
Fax: (214) 368-8754
|
||
Email: hhickey@excoresources.com
|
||
|
||
With a copy to:
|
||
|
||
EXCO Resources, Inc.
|
||
12377 Merit Drive, Suite 1700
|
||
Dallas, Texas 75251
|
||
Attention: William L. Boeing, Vice President
|
||
General Counsel, and Secretary
|
||
Telephone: (214) 368-2084
|
||
Fax : (214) 706-3409
|
||
Email : lboeing@EXCOResources.com
|
||
|
||
If to BG or any BG Member:
|
||
|
BG US Production Company, LLC
|
|
811 Main Street, Suite 3400
|
||
Houston, Texas 77002
|
||
Attention: Roger Coe
|
||
Telephone: (713) 599-4000
|
||
Fax: (713) 599-4250
|
||
E-mail: roger.coe@bg-group.com
|
||
|
|
BG US Production Company, LLC
|
811 Main Street, Suite 3400
|
|
Houston, Texas 77002
|
|
Attention: Chris Migura, Principal Counsel
|
|
Telephone: (713) 599-4000
|
|
Fax: (713) 599-4250
|
|
E-mail: chris.migura@bg-group.com
|
|
|
|
|
|
If to the Company or any Joint Entity:
|
|
|
|
12377 Merit Drive, Suite 1700
|
|
Dallas, Texas 75251
|
|
Attention: President and General Manager
|
|
Telephone: (214) 368-2084
|
|
Fax: (214) 368-8754
|
|
|
|
With a copy to:
|
|
|
|
Attention: Vice President, Legal
|
|
Telephone: (724) 720-2500
|
|
Fax: (724) 720-2505
|
|
|
(e)
|
Section 4.4(a)(iii)
shall be amended by deleting it in its entirety and replacing it with the following:
|
(f)
|
Section 4.4(c)
shall be amended by deleting it in its entirety and replacing it with the following:
|
(g)
|
Section 9.2(a)
shall be amended by deleting the phrase “the expiration of the sixty (60) day election period in Section 9.2(b)” and replacing it with “the end of the AMI Election Period”.
|
(h)
|
Section 9.2(b)
shall be amended by deleting the phrase “a period of sixty (60) days after receipt of the Offer Notice” and replacing it with the phrase “until the end of the AMI Election Period”.
|
(i)
|
Section 9.2(e)
shall be amended by deleting the phrase “within thirty (30) days of its receipt of the Offer Notice stating that it does not agree with the Acquiring Development Party’s statement of the Cash Value” and replacing it with the phrase “within twenty (20) days of its receipt of the Offer Notice stating that it does not agree with the Acquiring Development Party’s statement of the Cash Value”.
|
(j)
|
Section 14.2
shall be amended by deleting such section in its entirety and replacing it with the following:
|
If to EXCO:
|
|
|
EXCO Holding (PA), Inc.
12377 Merit Drive, Suite 1700
Dallas, Texas 75251
Attention: President
Telephone: (214) 368-2084
Fax: (214) 368-8754
|
|
with a copy to:
EXCO Resources, Inc.
12377 Merit Drive, Suite 1700
Dallas, Texas 75251
Attention: William L. Boeing, Vice President,
General Counsel, and Secretary
Telephone: (214) 368-2084
Fax: (214) 706-3409
|
If to BG:
|
|
BG US Production Company, LLC
811 Main Street, Suite 3400
Houston, Texas 77002
Attention: Roger Coe
Telephone: (713) 599-4000
Fax: (713) 599-4250
|
|
with a copy to:
BG US Production Company, LLC
811 Main Street, Suite 3400
Houston, Texas 77002
Attention: Chris Migura, Principal Counsel
Telephone: (713) 599-4000
Fax: (713) 599-4250
|
If to the Company:
|
|
|
EXCO Resources (PA), LLC
12377 Merit Drive, Suite 1700
Dallas, Texas 75251
Attention: President and General Manager
Telephone: (214) 368-2084
Fax: (214) 368-8754
With a copy to:
Attention: Vice President, Legal
Telephone: (724) 720-2500
Fax: (724) 720-2505
|
(k)
|
The definition of “
Technical Services
” in
Appendix I
shall be amended by deleting the term “HSSE” therefrom and replacing it with the term “EHS”.
|
(l)
|
The definition of “
Technical Services Costs
” in
Appendix I
shall be amended by deleting the term “HSSE” therefrom and replacing it with the term “EHS”.
|
(m)
|
Appendix I
shall be amended by deleting the definition for “Secondee”.
|
(n)
|
Appendix I
shall be amended by adding the following definitions in their correct alphabetic locations:
|
(o)
|
The JDA shall be amended by attaching Exhibit “K” attached hereto as Exhibit “K” to the JDA.
|
3.
|
Application of Certain Provisions.
The terms of Sections 13.1, 13.2, 14.1, 14.2, 14.3, 14.4, 14.6, 14.7, 14.8, 14.9, 14.10, 14.11, 14.12(a), 14.13 and 14.14 of the JDA are incorporated herein by reference as if set out in full herein.
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4.
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Ratification.
Except as amended herein, the terms and conditions of the JDA shall remain in full force and effect. Any and all references to the JDA shall hereafter refer to the JDA as amended by this Amendment.
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EXCO PRODUCTION COMPANY (PA), LLC
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By:
/s/ WILLIAM L. BOEING
Name: William L. Boeing
Title: Vice President and General Counsel
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EXCO PRODUCTION COMPANY (WV), LLC
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By:
/s/ WILLIAM L. BOEING
Name: William L. Boeing
Title: Vice President and General Counsel
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BG PRODUCTION COMPANY (PA), LLC
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By:
/s/ ROGER COE
Name: Roger Coe
Title: Vice President
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BG PRODUCTION COMPANY (WV), LLC
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By:
/s/ ROGER COE
Name: Roger Coe
Title: Vice President
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EXCO RESOURCES (PA), LLC
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By:
/s/ WILLIAM L. BOEING
Name: William L. Boeing
Title: Vice President and General Counsel
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1.
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Definitions and References.
Capitalized terms used in this Amendment and not otherwise defined herein have the meanings given such terms in the LLC Agreement. Sections, Articles, Appendices, Exhibits, Schedules and subsections referred to herein refer to such Sections, Articles, Appendices, Exhibits, Schedules and subsections of the LLC Agreement unless the context expressly states otherwise.
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2.
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LLC Agreement Amendment
. The LLC Agreement is hereby amended as follows:
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(a)
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Section 1.1 shall be amended by adding the following definitions in their correct alphabetical locations:
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(b)
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Section 1.1 shall be amended by deleting the definition of “Budgeted Acquisition.”
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(c)
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Section 2.2(x)
shall be amended by deleting it in its entirety and replacing it with the following:
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“(x)
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any acquisition of Oil and Gas Assets (other than Operating Assets in the ordinary course of business) for consideration in excess of five hundred thousand dollars (US$500,000) in any transaction or series of related transactions, but excluding any AMI Acquisition (for which no vote of the Management Board is required);”
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(d)
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Section 2.3(c)
shall be amended by deleting it in its entirety and replacing it with the following:
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“(c)
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delegation of authority to the officers of the Company to enter into certain Company Contracts (including Hydrocarbons sales agreements);”
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(e)
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Section 2.3(k) shall be amended by inserting the phrase “except as provided in Sections 2.11(g) and 2.11(h)” immediately following the reference to “Section 2.11(f).”
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(f)
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Section 2.3(p)
shall be amended by deleting it in its entirety and replacing it with the following:
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“(p)
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[omitted];”
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(g)
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Section 2.3(s)
shall be amended by deleting the phrase “and 2.11(b)(iii)”.
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(h)
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Section 2.3(y)
shall be amended by deleting the phrase “established by the Vice President of Finance and Business Services” and replacing it with the phrase “established by the officer of the Company principally responsible for the Company’s financial matters”.
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(i)
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Section 2.4(a)
shall be amended by deleting the first two sentences and replacing them with the following:
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(j)
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Section 2.5(d)
shall be amended by deleting it in its entirety and replacing it with the following:
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(k)
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Section 2.5(e)
shall be amended by deleting it in its entirety and replacing it with the following:
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(l)
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Section 2.5(f)
shall be amended by deleting it in its entirety and replacing it with the following:
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(m)
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Section 2.5(g)
shall be amended by deleting it in its entirety and replacing it with the following:
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(n)
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Section 2.5(i)
shall be amended by deleting the first sentence and replacing it with the following:
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(o)
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Section 2.5(o)
shall be amended by deleting it in its entirety and replacing it with the following:
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“(o)
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All notices and communications required or permitted to be given to the Board Members and the President and General Manager pursuant to this Article 2
shall be sufficient in all respects if given in writing and delivered personally, or sent by bonded overnight courier, or mailed by U.S. Express Mail or by certified or registered United States Mail with all postage fully prepaid, or sent by facsimile transmission, or by pdf via e-mail (provided that any such facsimile or email transmission is confirmed either orally or by written confirmation), addressed to the appropriate Group at the address for such Group shown below or at such other address as such Member shall have theretofore designated by written notice delivered to the Member giving such notice:
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If to the President and General Manager:
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EXCO Resources (PA), LLC
12377 Merit Drive, Suite 1700
Dallas, Texas 75251
Attention: President and General Manager
Telephone: (214) 368-2084
Fax: (214) 368-8754
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If to the EXCO Affiliate Group:
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EXCO Holding (PA), Inc.
12377 Merit Drive, Suite 1700 Dallas, Texas 75251 Attention: President Telephone: (214) 368-2084 Fax: (214) 368-8754
With a copy to:
EXCO Resources, Inc.
12377 Merit Drive, Suite 1700 Dallas, Texas 75251 Attention: William L. Boeing, General Counsel Telephone: (214) 368-2084 Fax: (214) 706-3409
E-mail: lboeing@excoresources.com
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If to the BG Affiliate Group:
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BG US Production Company, LLC
811 Main Street, Suite 3400 Houston, Texas 77002 Attention: Roger Coe Telephone: (713) 599-4000 Fax: (713) 599-4250
E-mail: roger.coe@bg-group.com
BG US Production Company, LLC
811 Main Street, Suite 3400 Houston, Texas 77002 Attention: Chris Migura, Principal Counsel Telephone: (713) 599-4000 Fax: (713) 599-4250
E-mail: chris.migura@bg-group.com
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(p)
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Section 2.5
shall be amended by adding the following subsections (p) and (r):
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“(p)
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In lieu of a vote taken at a meeting or a proposal distributed in accordance with Section 2.5(j), a written resolution of the Management Board will be effective to evidence the approval of the Management Board upon the signature of at least one of the Board Members or alternate Board Members from each Group.
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(r)
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Effective as of the 2014 Amendment Effective Date, at least ten (10) days prior to each meeting of the Management Board, the Company (or EXCO, to the extent that EXCO is acting as Service Provider) shall deliver to the Members (i) an organization chart for the organization supporting Company’s activities, (ii) a proposed allocation of employee or Secondee time for Company activities during the upcoming Calendar Quarter, (iii) an assessment of whether the preceding Calendar Quarter’s allocation of employee or Secondee time for Company activities should be modified, and (iv) a general listing of any significant activities performed or to be performed by employees or Secondees during the current Calendar Quarter which are not Development Operations or otherwise conducted for the benefit of both BG Member and EXCO Member pursuant to this Agreement or the benefit of Affiliates of both of them pursuant to the Joint Development Agreement
(such as efforts of EXCO or its Affiliates to support new business development or asset dispositions in which BG does not participate; provided, however, that proprietary information of EXCO and/or its Affiliates in which BG or its Affiliates do not also have a proprietary interest shall not be required to be included in such general listings), together with an estimate of the amount of time spent or to be spent by each individual on such activities during such Calendar Quarter. At each meeting of the Management Board, Company (or EXCO, to the extent that EXCO is acting as Service Provider) shall be prepared to explain and discuss how the various operational departments of Company (or EXCO, to the extent EXCO is acting as Service Provider) are resourced and whether such allocation of resources should be modified.”
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(q)
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Section 2.11(a)(i)
shall be amended by deleting it in its entirety and replacing it with the following:
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“(i)
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The Management Board shall have the power to elect, delegate authority to, and remove such officers of the Company as the Management Board may from time to time deem appropriate; provided, however, that each officer appointee of the Company shall serve a three (3) year term commencing as
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(r)
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Section 2.11(a)(ii)
shall be amended by deleting it in its entirety and replacing it with the following:
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“(ii)
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[omitted].”
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(s)
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Section 2.11(b)(i)
shall be amended by deleting the first sentence and replacing it with the following:
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(t)
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Section 2.11(b)(ii)
shall be amended by deleting the second sentence of such Section.
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(u)
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Section 2.11(b)(iii)
shall be amended by deleting it in its entirety and replacing it with the following:
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(v)
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Section 2.11(c)
shall be amended by deleting it in its entirety and replacing it with the following:
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“(c)
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Unless otherwise agreed by the Management Board, (i) all Secondees of the Company that are employees of a member of the EXCO Affiliate Group shall be seconded to the Company by the Members pursuant to a secondment agreement substantially in the form of Exhibit “A” attached hereto; and (ii) all Secondees of the Company that are employees of a member of the BG Affiliate Group shall be seconded to the Company by the Members pursuant to a secondment agreement substantially in the form of Exhibit “A-1” attached hereto. Simultaneously with the execution of this Agreement, each initial Member and the Company entered into a secondment agreement substantially in the form of Exhibit “A”. On the 2014 Amendment Effective Date, BG Member, Company and a certain member of the EXCO Affiliate Group shall enter into an amended and restated secondment agreement substantially in the form of Exhibit “A-1”, which such agreement shall be the Secondment Agreement for the BG Member. Each Affiliated Member Group with a Percentage Interest greater than twenty five percent (25%) shall have the right but not the obligation to second its or its Affiliates’ employees to the Company; provided, however, that the officers of the Company must
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(w)
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Section 2.11
shall be amended by adding the following subsection (g):
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“(g)
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If the BG Affiliate Group possesses a Percentage Interest greater than 25% and a Participating Interest of greater than 25% under the ET/NL JDA, the following provisions apply:
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(i)
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Subject to the terms of its Secondment Agreement, BG has the right but not the obligation to place Secondees in the positions identified on Exhibit “C” attached hereto (or to fill any Secondee vacancies of such positions) within the Company and/or EXCO (in its capacity as ET/NL Joint Development Operator in the East Texas/North Louisiana Area or Service Provider
in the Appalachian Area) for the primary purpose of supporting ET/NL Operations in the East Texas/North Louisiana Area and/or Development Operations in the Appalachian Area. Notwithstanding the foregoing, upon the prior written approval of BG (such approval not to be unreasonably withheld), the Company and/or EXCO, as applicable, shall each have the right in its reasonable discretion, to reallocate the Persons so dedicated to other similar positions with Company or EXCO, as applicable. Any such placement of Secondees by BG in such positions or filling of Secondee vacancies in such positions shall be made promptly by BG and in any event such Secondee shall be available for commencing work at the Company or EXCO, as applicable, within sixty (60) days after such positions become vacant. If such placement or filling of vacancy, and the availability of such Secondee for such work, is not made within such time, then (subject to Section 2.11(i)), EXCO shall have the right to fill such vacant position with a Secondee available for commencing work.
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(ii)
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If a position becomes available within any of the Primary Departments of the Company or EXCO (in its capacity as ET/NL Joint Development Operator in the East Texas/North Louisiana Area
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(iii)
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At any one time, BG may place up to three (3) GDP Members for training purposes within the Company and/or EXCO (in its capacity as ET/NL Joint Development Operator in the East Texas/North Louisiana Area or Service Provider in the Appalachian Area) in support of Development Operations in the Appalachian Area or ET/NL Operations in the East Texas/North Louisiana Area, in each case within the Primary Department designated by BG. EXCO will reasonably consider requests by BG for additional GDP Members. BG will be responsible for salary, wages and other direct employment costs of GDP Members. Each GDP Member will be placed in accordance with the BG Secondment Agreement.
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(iv)
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At the request of BG or EXCO, if the ET/NL Operations in the East Texas/North Louisiana Area or the Development Operations in the Appalachian Area materially change from the applicable operations in existence on March 1, 2013, BG and EXCO will meet to discuss amendments to the secondment rights of this Section 2.11(g) given such change in circumstances.”
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(x)
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Section 2.11
shall be amended by adding the following subsection (h):
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“(h)
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If at any time the BG Affiliate Group possesses a Percentage Interest greater than 25% but does not possess a Participating Interest greater than 25% under the ET/NL JDA, then BG will have the right but not the obligation to maintain each Secondee position filled pursuant to Section 2.11(g)(i) where the time of such Secondee has been more than 50% allocable to activities relating to Development Operations in the Appalachian Area during the 12 months preceding a reduction in the Participating Interest of the BG Affiliate Group to 25% or less and BG shall have the continuing general right, subject to
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(y)
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Section 2.11
shall be amended by adding the following subsection (i):
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“(i)
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Subject to Section 2.11(g)(i) and Section 2.11(g)(ii), if a position becomes available in one of the Primary Departments that predominantly supports Development Operations in the Appalachia Area and/or ET/NL Operations in the East Texas/North Louisiana Area and (i) the available position is at or above the level of supervisor or manager (but excluding officers and directors) within the Company or EXCO (in its capacity as ET/NL Joint Development Operator in the East Texas/North Louisiana Area or Service Provider in the Appalachian Area) or (ii) such position relates to an area in which BG has a vacancy in one of the positions described on Exhibit “C” (either because the position is described as ‘VACANT’ or because the identified individual vacated the position), then the Company or EXCO, as applicable, shall involve BG in the hiring decision regarding such position (or reallocation of an existing employee to such position) by submitting resumes of potential candidates to BG, by giving BG the opportunity to interview the candidate either (at BG’s option) in person in Dallas or remotely by phone or videoconference (provided that any such interview is conducted reasonably promptly by BG), and by involving BG in such other manner as BG may reasonably request; provided that BG shall not unreasonably delay or hinder the hiring process by EXCO. EXCO will reasonably consider BG requests for the placement of Secondees by BG into any such position (and, if EXCO determines that a candidate is unsuitable, to consider replacement candidates requested by BG) in addition to any rights that BG may have pursuant to Section 2.11(g)(i) and Section 2.11(g)(ii).”
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(z)
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Section 2.12
shall be amended by adding the following subsections (c), (d) and (e):
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“(c)
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For so long as EXCO is acting as Service Provider, EXCO shall actively involve BG in operations and activities which support Development Operations, including, without limitation, by providing a representative of BG the opportunity to participate in (or send another available BG representative to) organized pre-scheduled meetings relating to the Subject Oil and Gas Assets and/or Development Operations, including management
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(d)
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For so long as EXCO is acting as Service Provider, EXCO shall provide employees and contractors of BG and its Affiliates with unrestricted, on-demand, on-site access during regular business hours to EXCO’s (and its Affiliates’) physical land records and electronic land management system (as of the 2014 Amendment Effective Date, such system is Excalibur and the applicable computer terminals accessing such system are located in Dallas, Texas) for the purposes of manipulating, reviewing and working with land records (including running queries and producing reports and summaries) related to Subject Oil and Gas Assets owned by BG or its Affiliates. At BG’s cost and expense, EXCO shall cooperate with efforts by BG to remotely access EXCO’s (and its Affiliates’) land data and information to the extent related to such Subject Oil and Gas Assets. Notwithstanding the foregoing, EXCO shall only be required to provide access to any such electronic land management system to the extent that (i) providing such access would not violate the provisions of any applicable software or other license (if necessary, after reasonable inquiry by EXCO to the licensor seeking permission for such access), (ii) BG obtains any applicable software or other license that may be required in connection with such access (and BG acknowledges that none of EXCO or its Affiliates will be responsible for obtaining any such license for BG), and (iii) such land data and information held in electronic form related to such Subject Oil and Gas Assets is capable of being separated from land data and information held in electronic form that is related to other assets of EXCO or its Affiliates; provided that in each case of (i), (ii) and (iii), EXCO shall use its reasonable efforts to assist in accomplishing such requirement, but in no event shall EXCO or its Affiliates be required to incur any third party costs or pay any fees in connection therewith that BG is unwilling to reimburse.
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(e)
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To assist BG with any asset disposition analysis or efforts relating to its disposition of Subject Oil and Gas Assets, for so long as EXCO is acting as Service Provider, EXCO shall, at BG’s sole cost and expense and without any liability of EXCO or its Affiliates whatsoever (except for liabilities arising due to the willful misconduct of EXCO or its Affiliates), provide support services for any such asset disposition analysis or efforts including, without limitation, assisting with data presentation, providing responses to data requests by BG, providing access to records and data for third party due diligence, and gathering data for purchase and sale agreement representation and warranties; provided that no employee of EXCO or its Affiliates shall be required to make any presentations to potential purchasers. BG shall indemnify EXCO and its Affiliates and their respective employees and representatives for any and all claims and liabilities arising out of or related to any services provided pursuant to this Section in connection with any such
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(aa)
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Section 2.13(f)
shall be amended by deleting the phrase “the Vice President of EHS shall establish” and replacing it with the phrase “the officer of the Company principally responsible for the Company’s EHS functions shall establish”.
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“(xiv)
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within three (3) weeks from the end of each Calendar Quarter, a schedule showing the working interest and net revenue interests (including net working interest, royalty, overriding royalty, etc.) of BG (and its Affiliates) in each well (showing separately any percentage interest held indirectly by BG (and its Affiliates) as a Member of the Company or member of some other Person) as of the end of such Calendar Quarter;
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(xv)
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on or before the 15th of each month preceding an obligation or expiration month, the monthly lease maintenance calendars (payments, extensions and expirations) with land recommendations;
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(xvi)
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copies of all raw microseismic and seismic data, including reprocessing and interpretative data, analysis and reports for the Appalachia Area that (A) are in the possession of the Company or Service Provider, as applicable, (B) are not subject to Third Party confidentiality restrictions that have not been waived and (C) have been generated by EXCO or by a Third Party on behalf of the Company or Service Provider;
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(xvii)
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geographic information system data and shape files for the Appalachia Area that (A) are in the possession of the Company or Service Provider, as applicable, (B) are not subject to Third Party confidentiality restrictions that have not been waived and (C) have been generated by EXCO or by a Third Party on behalf of the Company or Service Provider, including any data layers or points associated with shape files such as lease expirations, depth severances and competitor drilling locations;
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(xviii)
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at the reasonable request of a Participating Member, a copy of general land data (as currently produced or compiled in the general course of business), inclusive of budget projections data, quarterly updates of activities associated with spending under land AFEs, division of interest calculations, quarterly acreage reports or title curative for the Appalachian Area that are in the possession of the Company or Service Provider, as applicable, are not subject to Third Party confidentiality restrictions that have not been waived and have been generated by EXCO or by a Third Party on behalf of the Company or Service Provider;
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(xix)
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at the reasonable request of a Participating Member that includes the applicable data query or queries, EXCO shall, within 30 days after receiving such request, provide such Participating Member with the results of specific data queries on EXCO’s land systems and databases,
provided
that the result of such queries provided to such Participating Member shall be limited to only those properties in which such Participating Member and EXCO own an interest under this Agreement;”
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(cc)
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Section 2.15(b)(i)
shall be amended by deleting the phrase “within 24 hours of the Vice President of HSSE receiving notice thereof” and replacing it with the phrase “within 24 hours of the officer of the Company principally responsible for the Company’s EHS functions receiving notice thereof”.
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(ee)
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Section 2.16(b)
shall be amended by replacing the phrase “for the purpose of observing operations or conducting HSSE and asset integrity audits” with the phrase “for the purpose of observing operations and conducting general audit activities, including conducting EHS and asset integrity audits”.
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“(f)
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Within ten (10) days after the end of each Calendar Month, Company shall provide each Member with a list of Development Operations Contracts relating to Development Operations entered into during the preceding Calendar Month that can reasonably be expected to result in aggregate payment to the counterparty of more than two hundred fifty thousand dollars (US$250,000), together with the status of any negotiations or tender processes relating to any unexecuted Development Operations Contracts as of the end of the Calendar Month.”
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(gg)
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Section 13.3
shall be amended by deleting it in its entirety and replacing it with the following:
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(hh)
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Each use of the term “HSSE” throughout the LLC Agreement shall be deleted and replaced with the term “EHS”. The defined terms in
Appendix I
previously beginning with the term “HSSE” and now beginning with the term “EHS” shall be reordered in the appropriate alphabetic locations.
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(ii)
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The LLC Agreement shall be amended by adding Exhibit “A-1” attached hereto immediately following Exhibit “A” of the LLC Agreement, as Exhibit “A-1” to the LLC Agreement.
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(jj)
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The LLC Agreement shall be amended by attaching Exhibit “C” attached hereto as Exhibit “C” to the LLC Agreement.
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3.
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Land Leasing Protocol.
Without determining whether or not such protocol was ever in effect, but for the avoidance of doubt, the “EXCO Resources (PA), LLC Land Leasing Protocol,” shall be void and without effect as of the Effective Date.
Accordingly, the Company shall not make land or oil and gas asset acquisitions without the approval of the BG Member and the EXCO Member; provided, however, that the approval of any such acquisition by the Management Board in accordance with the Management Board voting provisions and applicable Board Member voting thresholds, in each case as contained in the LLC Agreement, shall be considered approval by the BG Member and the EXCO Member, respectively, for the purposes of this provision.
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4.
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Application of Certain Provisions.
The terms of Sections 12.1, 12.2, 13.2, 13.3, 13.4, 13.5, 13.7, 13.8, 13.9, 13.10, 13.11, 13.12, 13.13(a), 13.14, 13.15 and 13.20 of the LLC Agreement are incorporated herein by reference as if set out in full herein.
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5.
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Ratification.
Except as amended herein, the terms and conditions of the LLC Agreement shall remain in full force and effect. Any and all references to the LLC Agreement shall hereafter refer to the LLC Agreement as amended by this Amendment.
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COMPANY:
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EXCO RESOURCES (PA), LLC
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By:
/s/ WILLIAM L. BOEING
Name: William L. Boeing
Title: Vice President and General Counsel
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MEMBERS:
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BG US PRODUCTION COMPANY, LLC
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By:
/s/ ROGER COE
Name: Roger Coe
Title: Vice President
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EXCO HOLDING (PA), INC
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By:
/s/ ROGER COE
Name: Roger Coe
Title: Vice President
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SOLELY FOR THE PURPOSES OF AMENDMENTS TO SECTION 2.11:
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EXCO OPERATING COMPANY, LP
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By: EXCO Partners OLP GP, LLC,
Its general partner
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By:
/s/ WILLIAM L. BOEING
Name: William L. Boeing
Title: Vice President and General Counsel
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1.
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Definitions and References.
Capitalized terms used in this Amendment and not otherwise defined herein have the meanings given such terms in the LLC Agreement. Sections, Articles, Appendices, Exhibits, Schedules and subsections referred to herein refer to such Sections, Articles, Appendices, Exhibits, Schedules and subsections of the LLC Agreement unless the context expressly states otherwise.
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2.
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LLC Agreement Amendment
. The LLC Agreement is hereby amended as follows:
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(a)
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Section 5.1(c)(ii)
shall be amended by deleting the phrase “(the Management Board shall use commercially reasonable efforts to make such delegations within thirty (30) days of the Closing Date)” in its entirety.
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(b)
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Section 5.1(c)(xx)
shall be amended by deleting the phrase “established by the Vice President of Finance and Business Services” and replacing it with the phrase “established by the officer of the Company principally responsible for the Company’s financial matters”.
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(c)
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Section 5.2
shall be amended by deleting the first two sentences and replacing them with the following:
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(d)
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Section 5.3(d)
shall be amended by deleting it in its entirety and replacing it with the following:
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(e)
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Section 5.3(e)
shall be amended by deleting it in its entirety and replacing it with the following:
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(f)
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Section 5.3(f)
shall be amended by deleting it in its entirety and replacing it with the following:
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(g)
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Section 5.3(g)
shall be amended by deleting it in its entirety and replacing the following:
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(h)
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Section 5.3(i) shall be amended by deleting the first sentence and replacing it with the following:
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(i)
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Section 5.3(o)
shall be amended by deleting it in its entirety and replacing it with the following:
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“(o)
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All notices and communications required or permitted to be given to the Board Members and the President and General Manager pursuant to this Article 5
shall be sufficient in all respects if given in writing and delivered personally, or sent by bonded overnight courier, or mailed by U.S. Express Mail or by certified or registered United States Mail with all postage fully prepaid, or sent by facsimile transmission, or by pdf e-mail (provided that any such facsimile transmission or e-mail transmission is confirmed either orally or by written confirmation), addressed to the appropriate Member at the address for such Member shown below or at such other address as such Member shall have theretofore designated by written notice delivered to the Member giving such notice:
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If to the President and General Manager:
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Appalachia Midstream, LLC
12377 Merit Drive, Suite 1700
Dallas, Texas 75251
Attention: President and General Manager
Telephone: (214) 368-2084
Fax: (214) 368-8754
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If to the EXCO Affiliate Group:
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EXCO Holding (PA), Inc.
12377 Merit Drive, Suite 1700 Dallas, Texas 75251 Attention: President Telephone: (214) 368-2084 Fax: (214) 368-8754
With a copy to:
EXCO Resources, Inc.
12377 Merit Drive, Suite 1700 Dallas, Texas 75251 Attention: William L. Boeing, General Counsel Telephone: (214) 368-2084 Fax: (214) 706-3409
E-mail: lboeing@excoresources.com
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If to the BG Affiliate Group:
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BG US Production Company, LLC
811 Main Street, Suite 3400 Houston, Texas 77002 Attention: Roger Coe Telephone: (713) 599-4000 Fax: (713) 599-4250
E-mail: roger.coe@bg-group.com
BG US Production Company, LLC
811 Main Street, Suite 3400 Houston, Texas 77002 Attention: Chris Migura, Principal Counsel Telephone: (713) 599-4000 Fax: (713) 599-4250
E-mail: chris.migura@bg-group.com
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(j)
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Section 5.3
shall be amended by adding the following subsection (p):
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“(p)
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In lieu of a vote taken at a meeting or to a proposal distributed in accordance with Section 5.3(j), a written resolution of the Management Board will be effective to evidence the approval of the Management Board upon the signature of at least one of the Board Members or alternate Board Members from each Group.”
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(k)
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Section 5.9(a)(i)
shall be amended by deleting it in its entirety and replacing it with the following:
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“(i)
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The Management Board shall have the power to elect, delegate authority to, and remove such officers of the Company and the other Company Group Members as the Management Board may from time to time deem appropriate; provided, however, that each officer appointee of the Company shall serve a three (3) year term commencing as of the date of the appointment of such officer, subject to each officer’s appointment being subject to an annual ratification vote by the Management Board. After any Management Board vote not to ratify the appointment of any officer, the Management Board shall, as soon as reasonably practicable thereafter, appoint a replacement officer, which replacement officer shall serve a three (3) year term (subject to annual ratification votes as described in this Section 5.9(a)(i)).”
|
(l)
|
Section 5.9(a)(ii)
shall be amended by deleting it in its entirety and replacing it with the following:
|
“(ii)
|
[omitted].”
|
(m)
|
Section 5.9(b)(i)
shall be amended by deleting the second sentence of such Section.
|
(n)
|
Section 5.9(b)(ii)
shall be amended by deleting it in its entirety and replacing it with the following:
|
(o)
|
Section 5.9(b)(iii)
shall be amended by deleting it in its entirety and replacing it with the following:
|
(p)
|
Section 5.9(b)(iv)
shall be amended by deleting it in its entirety and replacing it with the following:
|
(q)
|
Section 5.9(b)(v)
shall be amended by deleting it in its entirety and replacing it with the following:
|
(r)
|
Section 5.9(b)(vi)
shall be amended by deleting it in its entirety and replacing it with the following:
|
(s)
|
Section 5.9(b)(vii)
shall be amended by deleting it in its entirety and replacing it with the following:
|
(t)
|
Section 5.9(c)
shall be amended by deleting the first sentence of such section.
|
(u)
|
Section 5.10 shall be amended by adding the following subsections (d) and (e):
|
(v)
|
Section 5.12(b)(i)
shall be amended by deleting the phrase “within 24 hours of the Vice President of HSSE receiving notice thereof” and replacing it with the phrase
|
(w)
|
Section 5.12(b)(iv)
shall be amended by replacing the phrase “for the purpose of observing operations or conducting HSSE and asset integrity audits” with the phrase “for the purpose of observing operations and conducting general audit activities, including conducting EHS and asset integrity audits”.
|
(x)
|
Section 6.4
shall be amended by adding the following subsection (e):
|
(y)
|
Section 13.1(a)
shall be amended by deleting the phrase “Each Non-Acquiring Member shall have a period of sixty (60) days after receipt of the Offer Notice” and replacing it with the phrase “Each Non-Acquiring Member shall have until the end of the AMI Election Period”.
|
(z)
|
Section 13.1(f)
shall be amended by deleting the phrase “within thirty (30) days of its receipt of the Offer Notice stating that it does not agree with the Acquiring Member’s statement of the Cash Value” and replacing it with the phrase “within twenty (20) days of its receipt of the Offer Notice stating that it does not agree with the Acquiring Member’s statement of the Cash Value”.
|
(aa)
|
Section 16.2
shall be amended by deleting it in its entirety and replacing it with the following:
|
(bb)
|
Each use of the term “HSSE” throughout the LLC Agreement shall be deleted and replaced with the term “EHS”. The defined terms in
Appendix I
previously beginning with the term “HSSE” and now beginning with the term “EHS” shall be reordered in the appropriate alphabetic locations.
|
(cc)
|
Appendix I
shall be amended by deleting the following defined terms in their entirety:
|
(dd)
|
Appendix I
shall be amended by adding the following definitions in their correct alphabetic location:
|
3.
|
Application of Certain Provisions.
The terms of Sections 15.1, 15.2, 16.1, 16.2, 16.3, 16.4, 16.6, 16.7, 16.8, 16.9, 16.10, 16.11, 16.12(a), 16.13 and 16.14 of the LLC Agreement are incorporated herein by reference as if set out in full herein.
|
4.
|
Ratification.
Except as amended herein, the terms and conditions of the LLC Agreement shall remain in full force and effect. Any and all references to the LLC Agreement shall hereafter refer to the LLC Agreement as amended by this Amendment.
|
COMPANY:
|
|
EXCO APPALACHIA MIDSTREAM, LLC
|
|
|
|
|
|
By:
/s/ WILLIAM L. BOEING
Name: William L. Boeing
Title: Vice President and General Counsel
|
|
|
|
|
|
|
MEMBERS:
|
|
BG US PRODUCTION COMPANY, LLC
|
|
|
|
|
|
By:
/s/ ROGER COE
Name: Roger Coe
Title: Vice President
|
|
|
|
|
|
EXCO HOLDING (PA), INC
|
|
|
|
|
|
By:
/s/ WILLIAM L. BOEING
Name: William L. Boeing
Title: Vice President and General Counsel
|
|
|
|
Name of Subsidiary
|
|
State of
Incorporation |
EXCO Services, Inc.
|
|
Delaware
|
EXCO Equipment Leasing, LLC
|
|
Delaware
|
EXCO Partners GP, LLC
|
|
Delaware
|
EXCO GP Partners Old, LP
|
|
Delaware
|
EXCO Partners OLP GP, LLC
|
|
Delaware
|
EXCO Operating Company, LP
|
|
Delaware
|
EXCO Mid-Continent MLP, LLC
|
|
Delaware
|
EXCO Holding (PA), Inc.
|
|
Delaware
|
EXCO Production Company (PA), LLC
|
|
Delaware
|
EXCO Production Company (WV), LLC
|
|
Delaware
|
EXCO Resources (XA), LLC
|
|
Delaware
|
EXCO Holding MLP, Inc.
|
|
Texas
|
EXCO Land Company, LLC
|
|
Delaware
|
|
TULSA OFFICE
First Place Tower
15 East Fifth Street • Suite 3500
Tulsa, Oklahoma 74103-4350
(918) 587-5521 • Fax: (918) 587-2881
|
www.lkaengineers.com
|
|
|
NETHERLAND, SEWELL & ASSOCIATES, INC.
|
|
|
|
|
|
|
By:
|
/s/ C.H. (Scott) Rees III
|
|
|
|
C.H. (Scott) Rees III, P.E.
|
|
|
|
Chairman and Chief Executive Officer
|
|
|
|
|
|
Dallas, Texas
|
|
|
|
February 25, 2015
|
|
|
|
|
|
|
|
|
|
|
|
Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.
|
TBPE REGISTERED ENGINEERING FIRM F-1580
|
FAX (713) 651-0849
|
1100 LOUISIANA STREET SUITE 4600 HOUSTON, TEXAS 77002-5294
|
TELEPHONE (713) 651-9191
|
|
||||
|
|
|
|
|
|
|
|
/s/ Ryder Scott Company, L.P.
|
|
|
|
|
|
|
|
|
|
RYDER SCOTT COMPANY, L.P.
|
|
|
|
|
TBPE Firm Registration No. F-1580
|
SUITE 600, 1015 4TH STREET, S.W.
|
CALGARY, ALBERTA T2R 1J4
|
TEL (403) 262-2799
|
FAX (403) 262-2790
|
621 17TH STREET, SUITE 1550
|
DENVER, COLORADO 80293-1501
|
TEL (303) 623-9147
|
FAX (303) 623-4258
|
1.
|
I have reviewed this Annual Report on Form 10-K of EXCO Resources, Inc.;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
Date:
|
February 25, 2015
|
/s/ Harold L. Hickey
|
|
|
Harold L. Hickey
|
|
|
President and Chief Operating Officer
|
1.
|
I have reviewed this Annual Report on Form 10-K of EXCO Resources, Inc.;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
Date:
|
February 25, 2015
|
/s/ Richard A. Burnett
|
|
|
Richard A. Burnett
|
|
|
Vice President, Chief Financial Officer and Chief Accounting Officer
|
Date:
|
February 25, 2015
|
/s/ Harold L. Hickey
|
|
|
Harold L. Hickey
|
|
|
President and Chief Operating Officer
|
|
|
|
|
|
/s/ Richard A. Burnett
|
|
|
Richard A. Burnett
|
|
|
Vice President, Chief Financial Officer and Chief Accounting Officer
|
Attention: Mr. Harold L. Hickey
|
|
|
Re:
|
Estimated Proved Reserves and
|
|
|
|
|
Future Net Cash Flow
|
|
|
|
|
Constant Pricing
|
|
|
|
Very truly yours,
|
|
|
|
|
|
|
|
LEE KEELING AND ASSOCIATES, INC.
|
|
|
|
|
LKA7489-EXCO (PA) & (WV)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Reserves
|
|
Future Net Revenue (M$)
|
||||
|
|
Gas
|
|
Condensate
|
|
|
|
Present Worth
|
Category
|
|
(MMCF)
|
|
(MBBL)
|
|
Total
|
|
at 10%
|
|
|
|
|
|
|
|
|
|
Proved Developed Producing
|
|
439,024.3
|
|
0.0
|
|
926,651.4
|
|
570,348.4
|
Proved Developed Non-Producing
|
|
12,681.4
|
|
2.6
|
|
25,379.9
|
|
13,564.9
|
Proved Undeveloped
|
|
651,502.4
|
|
0.0
|
|
900,412.6
|
|
387,478.5
|
|
|
|
|
|
|
|
|
|
Total Proved
|
|
1,103,208.1
|
|
2.6
|
|
1,852,443.8
|
|
971,391.7
|
|
|
|
Sincerely,
|
|
|
|
|
|
|
|
|
|
NETHERLAND, SEWELL & ASSOCIATES, INC.
|
|
|
|
|
Texas Registered Engineering Firm F-2699
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
By: /s/ C.H. (Scott) Rees III
|
|
|
|
|
C.H. (Scott) Rees III, P.E.
|
|
|
|
|
Chairman and Chief Executive Officer
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
By: /s/ Robert C. Barg
|
|
|
By: /s/ William J. Knights
|
|
Robert C. Barg, P.E. 71656
|
|
|
William J. Knights, P.G. 1532
|
|
Senior Vice President
|
|
|
Vice President
|
|
|
|
|
|
|
Date Signed: January 19, 2015
|
|
|
Date Signed: January 19, 2015
|
|
|
|
|
|
|
Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.
|
(i)
|
Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
|
(ii)
|
Same environment of deposition;
|
(iii)
|
Similar geological structure; and
|
(iv)
|
Same drive mechanism.
|
(i)
|
Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
|
(ii)
|
Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
|
(i)
|
Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.
|
(ii)
|
Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.
|
(iii)
|
Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.
|
(iv)
|
Provide improved recovery systems.
|
(i)
|
Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.
|
(ii)
|
Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.
|
(iii)
|
Dry hole contributions and bottom hole contributions.
|
(iv)
|
Costs of drilling and equipping exploratory wells.
|
(v)
|
Costs of drilling exploratory-type stratigraphic test wells.
|
(i)
|
Oil and gas producing activities include:
|
(A)
|
The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;
|
(B)
|
The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;
|
(C)
|
The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:
|
(1)
|
Lifting the oil and gas to the surface; and
|
(2)
|
Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and
|
(D)
|
Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.
|
a.
|
The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and
|
b.
|
In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.
|
(ii)
|
Oil and gas producing activities do not include:
|
(A)
|
Transporting, refining, or marketing oil and gas;
|
(B)
|
Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;
|
(C)
|
Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or
|
(D)
|
Production of geothermal steam.
|
(i)
|
When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
|
(ii)
|
Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
|
(iii)
|
Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
|
(iv)
|
The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
|
(v)
|
Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
|
(vi)
|
Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.
|
(i)
|
When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
|
(ii)
|
Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
|
(iii)
|
Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
|
(iv)
|
See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.
|
(i)
|
Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and
|
(A)
|
Costs of labor to operate the wells and related equipment and facilities.
|
(B)
|
Repairs and maintenance.
|
(C)
|
Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.
|
(D)
|
Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.
|
(E)
|
Severance taxes.
|
(ii)
|
Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.
|
(i)
|
The area of the reservoir considered as proved includes:
|
(A)
|
The area identified by drilling and limited by fluid contacts, if any, and
|
(B)
|
Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
|
(ii)
|
In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
|
(iii)
|
Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
|
(iv)
|
Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
|
(A)
|
Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
|
(B)
|
The project has been approved for development by all necessary parties and entities, including governmental entities.
|
(v)
|
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending
|
(i)
|
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
|
(ii)
|
Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
|
•
|
The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);
|
•
|
The company's historical record at completing development of comparable long-term projects;
|
•
|
The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;
|
•
|
The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and
|
•
|
The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).
|
(iii)
|
Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such
|
/s/ Michael F. Stell
|
Michael F. Stell, P.E.
|
TBPE License No. 56416
|
Advising Senior Vice President
|
TBPE REGISTERED ENGINEERING FIRM F-1580
|
FAX (713) 651-0849
|
1100 LOUISIANA STREET SUITE 4600 HOUSTON, TEXAS 77002-5294
|
TELEPHONE (713) 651-9191
|
SUITE 600, 1015 4TH STREET, S.W.
|
CALGARY, ALBERTA T2R 1J4
|
TEL (403) 262-2799
|
FAX (403) 262-2790
|
621 17TH STREET, SUITE 1550
|
DENVER, COLORADO 80293-1501
|
TEL (303) 623-9147
|
FAX (303) 623-4258
|
As of December 31, 2014
|
|
|
Proved
|
||||||||||||||
|
|
Developed
|
|
|
|
Total
|
||||||||||
|
|
Producing
|
|
Non-Producing
|
|
Undeveloped
|
|
Proved
|
||||||||
Net Remaining Reserves
|
|
|
|
|
|
|
|
|
||||||||
Oil/Condensate – Barrels
|
|
14,285,273
|
|
|
358
|
|
|
3,257,560
|
|
|
17,543,191
|
|
||||
Plant Products – Barrels
|
|
387,035
|
|
|
0
|
|
|
54,260
|
|
|
441,295
|
|
||||
Gas – MMCF
|
|
4,389
|
|
|
0
|
|
|
748
|
|
|
5,137
|
|
||||
|
|
|
|
|
|
|
|
|
||||||||
Income Data (M$)
|
|
|
|
|
|
|
|
|
||||||||
Future Gross Revenue
|
|
|
$1,248,839
|
|
|
|
$31
|
|
|
|
$282,765
|
|
|
|
$1,531,635
|
|
Deductions
|
|
346,371
|
|
|
1
|
|
|
147,056
|
|
|
493,428
|
|
||||
Future Net Income (FNI)
|
|
$
|
902,468
|
|
|
|
$30
|
|
|
|
$135,709
|
|
|
|
$1,038,207
|
|
|
|
|
|
|
|
|
|
|
||||||||
Discounted FNI @ 10%
|
|
$
|
512,711
|
|
|
|
$28
|
|
|
$
|
50,783
|
|
|
$
|
563,522
|
|
|
|
Discounted Future Net Income (M$)
|
||
|
|
As of December 31, 2014
|
||
Discount Rate
|
|
Total
|
|
|
Percent
|
|
Proved
|
|
|
|
|
|
|
|
5
|
|
$723,978
|
|
|
15
|
|
$467,471
|
|
|
20
|
|
$403,584
|
|
|
25
|
|
$357,916
|
|
(1)
|
completion intervals which are open at the time of the estimate, but which have not started producing;
|
(2)
|
wells which were shut-in for market conditions or pipeline connections; or
|
(3)
|
wells not capable of production for mechanical reasons.
|
(i)
|
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
|
Attention: Mr. Harold L. Hickey
|
|
|
Re:
|
Estimated Proved Reserves and
|
|
|
|
|
Future Net Cash Flow
|
|
|
|
|
Constant Pricing
|
|
|
Very truly yours,
|
|
|
LEE KEELING AND ASSOCIATES, INC.
|