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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Delaware
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74-3169953
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(State or Other Jurisdiction of
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(I.R.S. Employer
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Incorporation or Organization)
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Identification No.)
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707 Wilshire Boulevard, Suite 4600
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Los Angeles, California
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90017
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(Address of Principal Executive Offices)
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(Zip Code)
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Page
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No.
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PART I
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PART II
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PART III
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PART IV
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•
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Permian Basin in Texas and New Mexico;
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•
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Midwest (Michigan, Indiana and Kentucky);
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•
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Ark-La-Tex (Arkansas, Louisiana and East Texas);
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•
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Mid-Continent (Oklahoma);
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•
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Rockies (Wyoming and Colorado);
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•
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California; and
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•
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Southeast (Florida and Alabama).
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•
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acquire long-lived assets with low-risk exploitation and development opportunities;
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•
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use our technical expertise and state-of-the-art technologies to identify and implement successful exploitation techniques to optimize reserve recovery;
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•
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reduce cash flow volatility through commodity price and interest rate derivatives; and
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•
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maximize asset value and cash flow stability through our operating and technical expertise.
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Antrim Shale
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Spraberry Trend
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||||||||||||||||||||
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2016
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2015
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2014
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2016
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2015
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2014
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||||||||||||
Net Production
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|||||||||||||
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Crude Oil (MBbl)
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—
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|
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—
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—
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1,059
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1,302
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1,458
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||||||
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NGL (MBbl)
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—
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—
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—
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589
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616
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643
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||||||
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Natural Gas (MMcf)
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12,793
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13,390
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13,902
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2,884
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3,069
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3,136
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||||||
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Total (MBoe)
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2,133
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2,233
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2,317
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2,128
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2,429
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2,623
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||||||
Average Realized Sales Price
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|||||||||||||
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Crude Oil price per Bbl
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$
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—
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$
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—
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$
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—
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$
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39.62
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$
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45.05
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$
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85.49
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NGL price per Bbl
|
—
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|
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—
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|
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—
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11.93
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|
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11.77
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26.74
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||||||
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Natural Gas price per Mcf
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2.52
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2.94
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5.29
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1.89
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2.10
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3.66
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||||||
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Total price per Boe
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$
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15.13
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$
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17.66
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$
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31.79
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$
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25.58
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$
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29.79
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$
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58.45
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Average Production Cost per Boe
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|||||||||||||
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Pre-tax lease operating expense
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$
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8.27
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$
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8.54
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$
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10.35
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$
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12.82
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|
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$
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15.39
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|
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$
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10.77
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Oil Wells
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Gas Wells
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||||||||
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Gross
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Net
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Gross
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Net
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||||
Operated
|
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5,088
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4,913
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2,807
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2,298
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Non-operated
|
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1,726
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83
|
|
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2,347
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|
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776
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Total
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6,814
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4,996
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5,154
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3,074
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Developed Acreage
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Undeveloped Acreage
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Total Acreage
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||||||||||||
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Gross
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Net
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Gross
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Net
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Gross
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Net
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||||||
Permian Basin
|
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110,156
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75,028
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14,832
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10,358
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124,988
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85,386
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Midwest
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493,967
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251,085
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13,204
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12,687
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507,171
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263,772
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Ark-La-Tex
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116,990
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75,599
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5,182
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|
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3,451
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|
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122,172
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79,050
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Mid-Continent
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32,094
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30,773
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|
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—
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—
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32,094
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30,773
|
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Rockies
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177,352
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|
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101,452
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26,304
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8,967
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203,656
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|
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110,419
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California
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3,956
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3,216
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41
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|
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41
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3,997
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3,257
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Southeast
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52,031
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47,193
|
|
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5,539
|
|
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3,694
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|
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57,570
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|
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50,887
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Total
|
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986,546
|
|
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584,346
|
|
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65,102
|
|
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39,198
|
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1,051,648
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623,544
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|
|
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2017 Expirations
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2018 Expirations
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2019 Expirations
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|||||||||||||
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Net Undeveloped Acreage
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Net Acreage without Extension Option
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Net Acreage with Extension Option
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Net Acreage without Extension Option
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Net Acreage with Extension Option
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Net Acreage without Extension Option
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Net Acreage with Extension Option
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|||||||
Permian Basin
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10,358
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|
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63
|
|
|
320
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|
|
233
|
|
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3
|
|
|
351
|
|
|
—
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Midwest
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12,687
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|
|
544
|
|
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1,157
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40
|
|
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—
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30
|
|
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—
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Ark-La-Tex
|
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3,451
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|
|
—
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|
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13
|
|
|
29
|
|
|
7
|
|
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—
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|
|
—
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Rockies
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8,967
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|
|
960
|
|
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—
|
|
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36
|
|
|
—
|
|
|
—
|
|
|
—
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California
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|
41
|
|
|
—
|
|
|
—
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|
|
34
|
|
|
—
|
|
|
—
|
|
|
—
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Southeast
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|
3,694
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|
|
400
|
|
|
—
|
|
|
3,294
|
|
|
—
|
|
|
1,297
|
|
|
—
|
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Total
|
|
39,198
|
|
|
1,967
|
|
|
1,490
|
|
|
3,666
|
|
|
10
|
|
|
1,678
|
|
|
—
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Year Ended December 31,
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|||||||
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2016
|
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2015
|
|
2014
|
|||
Gross development wells:
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|
|
|
|
|
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|||
Productive
|
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25
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|
|
62
|
|
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170
|
|
Dry
|
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—
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|
|
—
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|
|
1
|
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Total
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25
|
|
|
62
|
|
|
171
|
|
Net development wells:
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|
|
|
|
|
|
|
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Productive
|
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9
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|
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45
|
|
|
160
|
|
Dry
|
|
—
|
|
|
—
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|
|
1
|
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Total
|
|
9
|
|
|
45
|
|
|
161
|
|
•
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require the acquisition of various permits before exploration, drilling or production activities commence;
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•
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prohibit some or all of the operations of facilities deemed in non-compliance with regulatory requirements;
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•
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restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling, production and transportation activities;
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•
|
limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and
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•
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require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits, plug abandoned wells and restore drilling sites.
|
•
|
the location of wells;
|
•
|
the method of drilling and casing wells;
|
•
|
the surface use and restoration of properties upon which wells are drilled;
|
•
|
the plugging and abandoning of wells; and
|
•
|
notice to surface owners and other third parties.
|
•
|
our ability to develop, confirm and consummate a plan of reorganization;
|
•
|
the high costs of bankruptcy proceedings and related fees;
|
•
|
our ability to obtain court approval with respect to motions filed in the Chapter 11 Cases from time to time;
|
•
|
our ability to obtain sufficient financing to allow us to emerge from Chapter 11 and execute our business plan post-emergence;
|
•
|
our ability to maintain our relationships with our suppliers, customers, other third parties and our employees;
|
•
|
our ability to maintain contracts that are critical to our operations;
|
•
|
our ability to execute our business plan in the current depressed commodity price environment;
|
•
|
our ability to attract, motivate and retain key employees;
|
•
|
the ability of third parties to seek and obtain court approval to terminate contracts and other agreements with us;
|
•
|
the ability of third parties to seek and obtain court approval to convert the Chapter 11 Cases to cases under Chapter 7 of the Bankruptcy Code; and
|
•
|
the actions and decisions of our creditors and other third parties who have interests in our Chapter 11 Cases that may be inconsistent with our plans.
|
•
|
domestic and foreign supply of and demand for oil, NGLs and natural gas;
|
•
|
market prices of oil, NGLs and natural gas;
|
•
|
level of consumer product demand;
|
•
|
overall domestic and global political and economic conditions;
|
•
|
political and economic conditions in producing countries, including those in the Middle East, Russia, South America and Africa;
|
•
|
actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil price and production controls;
|
•
|
weather conditions;
|
•
|
impact of the U.S. dollar exchange rates on commodity prices;
|
•
|
technological advances affecting energy consumption and energy supply;
|
•
|
domestic and foreign governmental regulations and taxation;
|
•
|
impact of energy conservation efforts;
|
•
|
capacity, cost and availability of oil and natural gas pipelines, processing, gathering and other transportation facilities and the proximity of these facilities to our wells;
|
•
|
increase in imports of liquid natural gas in the United States; and
|
•
|
price and availability of alternative fuels.
|
•
|
the value of our reserves, because declines in oil and natural gas prices would reduce the amount of oil and natural gas that we can produce economically;
|
•
|
the amount of cash flow available for capital expenditures;
|
•
|
our ability to replace our production and future rate of growth;
|
•
|
our ability to borrow money or raise additional capital and our cost of such capital; and
|
•
|
our ability to meet our financial obligations.
|
•
|
high costs, shortages or delivery delays of drilling rigs, equipment, labor or other services;
|
•
|
unexpected operational events and drilling conditions;
|
•
|
sustained depressed oil and natural gas prices and further reductions in oil and natural gas prices;
|
•
|
limitations in the market for oil and natural gas;
|
•
|
problems in the delivery of oil and natural gas to market;
|
•
|
adverse weather conditions;
|
•
|
facility or equipment malfunctions;
|
•
|
equipment failures or accidents;
|
•
|
title problems;
|
•
|
pipe or cement failures;
|
•
|
casing collapses;
|
•
|
compliance with environmental and other governmental requirements;
|
•
|
environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases;
|
•
|
lost or damaged oilfield drilling and service tools;
|
•
|
unusual or unexpected geological formations;
|
•
|
loss of drilling fluid circulation;
|
•
|
pressure or irregularities in formations;
|
•
|
fires, blowouts, surface craterings and explosions;
|
•
|
natural disasters; and
|
•
|
uncontrollable flows of oil, natural gas or well fluids.
|
•
|
future oil and natural gas prices;
|
•
|
production levels;
|
•
|
capital expenditures;
|
•
|
operating and development costs;
|
•
|
the effects of regulation;
|
•
|
the accuracy and reliability of the underlying engineering and geologic data; and
|
•
|
the availability of funds.
|
•
|
the actual prices we receive for oil and natural gas;
|
•
|
our actual operating costs in producing oil and natural gas;
|
•
|
the amount and timing of actual production;
|
•
|
the amount and timing of our capital expenditures;
|
•
|
supply of and demand for oil and natural gas; and
|
•
|
changes in governmental regulations or taxation.
|
•
|
your proportionate ownership interest in us may decrease;
|
•
|
the relative voting strength of each previously outstanding Common Unit may be diminished; and
|
•
|
the market price of the Common Units may decline.
|
•
|
provides that our General Partner shall not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith, meaning it believed that the decisions were in the best interests of the Partnership;
|
•
|
generally provides that affiliate transactions and resolutions of conflicts of interest not approved by the conflicts committee of the Board and not involving a vote of unitholders will not constitute a breach of our partnership agreement or of any fiduciary duty if they are on terms no less favorable to us than those generally provided to or available from unrelated third parties or are “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our General Partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;
|
•
|
provides that in resolving conflicts of interest where approval of the conflicts committee of the Board is not sought, it will be presumed that in making its decision the Board acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us challenging such approval, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption; and
|
•
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provides that our General Partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our General Partner or those other persons acted in bad faith or engaged in fraud or willful misconduct.
|
•
|
we were conducting business in a state but had not complied with that particular state’s partnership statute; or
|
•
|
your right to act with other unitholders to elect the directors of our General Partner, to remove or replace our General Partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constituted participation in “control” of our business.
|
|
|
Year Ended December 31,
|
||||||||||||||||||
Thousands of dollars, except per unit amounts
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil, natural gas and NGL sales
|
|
$
|
504,254
|
|
|
$
|
645,272
|
|
|
$
|
855,820
|
|
|
$
|
660,665
|
|
|
$
|
413,867
|
|
(Loss) gain on commodity derivative instruments, net
|
|
(53,091
|
)
|
|
438,614
|
|
|
566,533
|
|
|
(29,182
|
)
|
|
5,580
|
|
|||||
Other revenue, net
|
|
17,842
|
|
|
24,829
|
|
|
7,616
|
|
|
3,175
|
|
|
3,548
|
|
|||||
Total revenue
|
|
469,005
|
|
|
1,108,715
|
|
|
1,429,969
|
|
|
634,658
|
|
|
422,995
|
|
|||||
Impairment of oil and natural gas properties
|
|
283,270
|
|
|
2,377,615
|
|
|
149,000
|
|
|
54,373
|
|
|
12,313
|
|
|||||
Impairment of goodwill
|
|
—
|
|
|
95,947
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Operating (loss) income
|
|
(576,807
|
)
|
|
(2,376,582
|
)
|
|
545,967
|
|
|
44,276
|
|
|
21,700
|
|
|||||
Net (loss) income
|
|
(816,133
|
)
|
|
(2,583,013
|
)
|
|
421,316
|
|
|
(43,671
|
)
|
|
(40,739
|
)
|
|||||
Less: Net (loss) income attributable to noncontrolling interest
|
|
(1,182
|
)
|
|
326
|
|
|
(17
|
)
|
|
—
|
|
|
62
|
|
|||||
Net (loss) income attributable to the partnership
|
|
$
|
(814,951
|
)
|
|
$
|
(2,583,339
|
)
|
|
$
|
421,333
|
|
|
$
|
(43,671
|
)
|
|
$
|
(40,801
|
)
|
Basic net (loss) income per unit
|
|
$
|
(3.90
|
)
|
|
$
|
(12.39
|
)
|
|
$
|
3.04
|
|
|
$
|
(0.43
|
)
|
|
$
|
(0.56
|
)
|
Diluted net (loss) income per unit
|
|
$
|
(3.90
|
)
|
|
$
|
(12.39
|
)
|
|
$
|
3.02
|
|
|
$
|
(0.43
|
)
|
|
$
|
(0.56
|
)
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Net cash provided by operating activities
|
|
$
|
174,460
|
|
|
$
|
436,705
|
|
|
$
|
357,755
|
|
|
$
|
257,166
|
|
|
$
|
191,782
|
|
Net cash used in investing activities
|
|
(72,428
|
)
|
|
(274,003
|
)
|
|
(837,004
|
)
|
|
(1,465,805
|
)
|
|
(697,159
|
)
|
|||||
Net cash (used in) provided by financing activities
|
|
(41,372
|
)
|
|
(164,866
|
)
|
|
489,419
|
|
|
1,206,590
|
|
|
504,556
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Balance Sheet Data (at period end):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Cash
|
|
$
|
71,124
|
|
|
$
|
10,464
|
|
|
$
|
12,628
|
|
|
$
|
2,458
|
|
|
$
|
4,507
|
|
Other current assets
|
|
559,632
|
|
|
577,863
|
|
|
588,080
|
|
|
114,604
|
|
|
109,158
|
|
|||||
Net property, plant and equipment
|
|
3,413,646
|
|
|
3,932,882
|
|
|
6,454,201
|
|
|
3,915,376
|
|
|
2,711,893
|
|
|||||
Other assets
|
|
71,006
|
|
|
314,178
|
|
|
583,425
|
|
|
163,844
|
|
|
89,936
|
|
|||||
Total assets
|
|
$
|
4,115,408
|
|
|
$
|
4,835,387
|
|
|
$
|
7,638,334
|
|
|
$
|
4,196,282
|
|
|
$
|
2,915,494
|
|
Current liabilities
|
|
$
|
1,354,200
|
|
|
$
|
318,006
|
|
|
$
|
361,556
|
|
|
$
|
182,889
|
|
|
$
|
115,240
|
|
Liabilities subject to compromise
|
|
1,879,176
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Long-term debt
|
|
3,094
|
|
|
2,830,342
|
|
|
3,247,160
|
|
|
1,889,675
|
|
|
1,100,696
|
|
|||||
Other long-term liabilities
|
|
272,911
|
|
|
281,144
|
|
|
263,442
|
|
|
133,898
|
|
|
110,022
|
|
|||||
Partners' equity
|
|
599,016
|
|
|
1,398,571
|
|
|
3,759,291
|
|
|
1,989,820
|
|
|
1,589,536
|
|
|||||
Noncontrolling interest
|
|
7,011
|
|
|
7,324
|
|
|
6,885
|
|
|
—
|
|
|
—
|
|
|||||
Total liabilities and partners' equity
|
|
$
|
4,115,408
|
|
|
$
|
4,835,387
|
|
|
$
|
7,638,334
|
|
|
$
|
4,196,282
|
|
|
$
|
2,915,494
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash distributions declared per unit outstanding:
|
|
$
|
—
|
|
|
$
|
0.3333
|
|
|
$
|
1.7581
|
|
|
$
|
1.9125
|
|
|
$
|
1.8300
|
|
•
|
the financial performance of our assets, without regard to financing methods, capital structure or historical cost basis;
|
•
|
our operating performance and return on capital as compared to those of other companies in our industry, without regard to financing or capital structure;
|
•
|
the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities; and
|
•
|
the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and, historically, to pay distributions.
|
|
|
Year Ended December 31,
|
||||||||||||||||||
Thousands of dollars
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
Reconciliation of net cash flows from operating activities to Adjusted EBITDA:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash provided by operating activities
|
|
$
|
174,460
|
|
|
$
|
436,705
|
|
|
$
|
357,755
|
|
|
$
|
257,166
|
|
|
$
|
191,782
|
|
Increase in assets (net of liabilities) relating to operating activities
|
|
(68,628
|
)
|
|
16,369
|
|
|
(4,057
|
)
|
|
32,105
|
|
|
22,492
|
|
|||||
Interest expense, net of capitalized interest (a)
|
|
124,093
|
|
|
183,852
|
|
|
120,143
|
|
|
80,617
|
|
|
61,807
|
|
|||||
Cash reorganization items
|
|
36,727
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Income from equity affiliates, net
|
|
593
|
|
|
104
|
|
|
(178
|
)
|
|
(55
|
)
|
|
(487
|
)
|
|||||
Other
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(21
|
)
|
|
(82
|
)
|
|||||
Income taxes
|
|
(634
|
)
|
|
258
|
|
|
101
|
|
|
562
|
|
|
400
|
|
|||||
Non-controlling interest
|
|
1,182
|
|
|
(326
|
)
|
|
17
|
|
|
—
|
|
|
(62
|
)
|
|||||
Gain on marketable securities
|
|
(464
|
)
|
|
(135
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Adjusted EBITDA
|
|
$
|
267,329
|
|
|
$
|
636,827
|
|
|
$
|
473,781
|
|
|
$
|
370,374
|
|
|
$
|
275,850
|
|
•
|
acquire long-lived assets with low-risk exploitation and development opportunities;
|
•
|
use our technical expertise and state-of-the-art technologies to identify and implement successful exploitation techniques to optimize reserve recovery;
|
•
|
reduce cash flow volatility through commodity price and interest rate derivatives; and
|
•
|
maximize asset value and cash flow stability through our operating and technical expertise.
|
|
|
Payments Due by Year
|
||||||||||||||||||||||||||
Thousands of dollars
|
|
2017
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
Thereafter
|
|
Total
|
||||||||||||||
Credit Agreement (a)
|
|
$
|
1,198,259
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,198,259
|
|
Senior Notes (b)
|
|
1,805,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,805,000
|
|
|||||||
Promissory note
|
|
—
|
|
|
—
|
|
|
2,938
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,938
|
|
|||||||
Operating lease obligations
|
|
4,866
|
|
|
3,467
|
|
|
2,570
|
|
|
2,476
|
|
|
2,460
|
|
|
5,714
|
|
|
21,553
|
|
|||||||
Asset retirement obligations (c)
|
|
5,905
|
|
|
8,382
|
|
|
263
|
|
|
3,405
|
|
|
2,718
|
|
|
237,821
|
|
|
258,494
|
|
|||||||
Total
|
|
$
|
3,014,030
|
|
|
$
|
11,849
|
|
|
$
|
5,771
|
|
|
$
|
5,881
|
|
|
$
|
5,178
|
|
|
$
|
243,535
|
|
|
$
|
3,286,244
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
(a) The commencement of the Chapter 11 Cases resulted in the acceleration of our obligations under the RBL Credit Agreement and, as such, the RBL Credit Agreement balance is reflected in current portion of long-term debt on the consolidated balance sheet at December 31, 2016. Interest expense continues to be recognized and paid on the RBL Credit Agreement subsequent to the Chapter 11 Filing Date, at the default rate of 7.00% at December 31, 2016. This table does not include future commitment fees or interest expense related to the RBL Credit Agreement, as we cannot determine with accuracy the timing of emergence from Chapter 11. The unused portion of the credit facility under the RBL Credit Agreement is subject to a commitment fee of 0.50% per annum.
|
||||||||||||||||||||||||||||
(b) Represents 9.25% Senior Secured Notes due 2020 with a face value of $650 million, 8.625% Senior Notes due 2020 with a face value of $305 million and 7.875% Senior Notes due 2022 with a face value of $850 million. As of December 31, 2016, the Senior Notes were in default and reflected in liabilities subject to compromise on the consolidated balance sheet. Accrued interest payable as of the Chapter 11 Filing Date was approximately $61.9 million. This amount is not included in this table but is reflected in liabilities subject to compromise on the consolidated balance sheets. No interest expense has been recognized subsequent to the Chapter 11 Filing Date.
|
||||||||||||||||||||||||||||
(c) Amounts represent our estimate of future asset retirement obligations on an discounted basis. See Note 11 to the consolidated financial statements in this report.
|
Name
|
|
Age
|
|
Position with Breitburn GP LLC
|
Halbert S. Washburn
|
|
56
|
|
Chief Executive Officer, Director
|
Mark L. Pease
|
|
60
|
|
President and Chief Operating Officer
|
James G. Jackson
|
|
52
|
|
Executive Vice President and Chief Financial Officer
|
Gregory C. Brown
|
|
65
|
|
Executive Vice President, General Counsel and Chief Administrative Officer
|
W. Jackson Washburn
|
|
54
|
|
Senior Vice President
|
Thomas E. Thurmond
|
|
43
|
|
Senior Vice President
|
Bruce D. McFarland
|
|
60
|
|
Vice President and Treasurer
|
Lawrence C. Smith
|
|
63
|
|
Vice President, Controller and Chief Accounting Officer
|
John R. Butler, Jr.*
|
|
78
|
|
Chairman of the Board
|
Randall H. Breitenbach
|
|
56
|
|
Vice Chairman of the Board
|
David B. Kilpatrick*
|
|
67
|
|
Director
|
Gregory J. Moroney*
|
|
65
|
|
Director
|
Charles S. Weiss*
|
|
64
|
|
Director
|
Donald D. Wolf*
|
|
73
|
|
Director
|
|
|
BREITBURN ENERGY PARTNERS LP
|
|
|
|
|
|
|
|
By:
|
BREITBURN GP LLC,
|
|
|
|
its General Partner
|
|
|
|
|
Dated:
|
March 8, 2017
|
By:
|
/s/ Halbert S. Washburn
|
|
|
|
Halbert S. Washburn
|
|
|
|
Chief Executive Officer
|
Name
|
|
Title
|
|
Date
|
|
|
|
|
|
|
|
|
|
|
/s/ Halbert S. Washburn
|
|
Chief Executive Officer and Director of
|
|
March 8, 2017
|
Halbert S. Washburn
|
|
Breitburn GP LLC
|
|
|
|
|
(Principal Executive Officer)
|
|
|
|
|
|
|
|
/s/ James G. Jackson
|
|
Chief Financial Officer of
|
|
March 8, 2017
|
James G. Jackson
|
|
Breitburn GP LLC
|
|
|
|
|
(Principal Financial Officer)
|
|
|
|
|
|
|
|
/s/ Lawrence C. Smith
|
|
Vice President, Controller and Chief
|
|
March 8, 2017
|
Lawrence C. Smith
|
|
Accounting Officer of
|
|
|
|
|
Breitburn GP LLC
|
|
|
|
|
(Principal Accounting Officer)
|
|
|
|
|
|
|
|
/s/ John R. Butler, Jr.
|
|
Chairman of the Board of
|
|
March 8, 2017
|
John R. Butler, Jr.
|
|
Breitburn GP LLC
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Randall H. Breitenbach
|
|
Vice Chairman of the Board
|
|
March 8, 2017
|
Randall H. Breitenbach
|
|
Breitburn GP LLC
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ David B. Kilpatrick
|
|
Director of
|
|
March 8, 2017
|
David B. Kilpatrick
|
|
Breitburn GP LLC
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Gregory J. Moroney
|
|
Director of
|
|
March 8, 2017
|
Gregory J. Moroney
|
|
Breitburn GP LLC
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Charles S. Weiss
|
|
Director of
|
|
March 8, 2017
|
Charles S. Weiss
|
|
Breitburn GP LLC
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Donald D. Wolf
|
|
Director of
|
|
March 8, 2017
|
Donald D. Wolf
|
|
Breitburn GP LLC
|
|
|
|
|
|
|
|
|
|
|
Consolidated Statements of Comprehensive
(Loss) Income
|
|
|
|
|
|
|
|
|
|
Supplemental Information
(unaudited)
|
|
|
|
|
/s/ Halbert S. Washburn
|
|
/s/ James G. Jackson
|
Halbert S. Washburn
|
|
James G. Jackson
|
Chief Executive Officer of Breitburn GP LLC
|
|
Chief Financial Officer of Breitburn GP LLC
|
/s/ PricewaterhouseCoopers LLP
|
Los Angeles, California
|
March 8, 2017
|
|
|
December 31,
|
||||||
Thousands of dollars
|
|
2016
|
|
2015
|
||||
ASSETS
|
|
|
|
|
||||
Current assets
|
|
|
|
|
||||
Cash
|
|
$
|
71,124
|
|
|
$
|
10,464
|
|
Accounts and other receivables, net (note 3)
|
|
549,544
|
|
|
128,589
|
|
||
Derivative instruments (note 5)
|
|
—
|
|
|
439,627
|
|
||
Related party receivables (note 6)
|
|
860
|
|
|
2,274
|
|
||
Inventory
|
|
998
|
|
|
926
|
|
||
Prepaid expenses and other current assets
|
|
8,230
|
|
|
6,447
|
|
||
Total current assets
|
|
630,756
|
|
|
588,327
|
|
||
Equity investments
|
|
7,160
|
|
|
6,567
|
|
||
Property, plant and equipment
|
|
|
|
|
||||
Oil and natural gas properties (note 4)
|
|
7,907,136
|
|
|
7,898,117
|
|
||
Other property, plant and equipment (note 4)
|
|
192,724
|
|
|
188,795
|
|
||
|
|
8,099,860
|
|
|
8,086,912
|
|
||
Accumulated depletion, depreciation and impairment (note 7)
|
|
(4,686,214
|
)
|
|
(4,154,030
|
)
|
||
Net property, plant and equipment
|
|
3,413,646
|
|
|
3,932,882
|
|
||
Other long-term assets
|
|
|
|
|
||||
Derivative instruments (note 5)
|
|
—
|
|
|
226,764
|
|
||
Other long-term assets (note 8)
|
|
63,846
|
|
|
80,847
|
|
||
Total assets
|
|
$
|
4,115,408
|
|
|
$
|
4,835,387
|
|
LIABILITIES AND EQUITY
|
|
|
|
|
||||
Current liabilities:
|
|
|
|
|
||||
Accounts payable
|
|
$
|
47,838
|
|
|
$
|
50,412
|
|
Current portion of long-term debt (note 9)
|
|
1,198,259
|
|
|
154,000
|
|
||
Derivative instruments (note 5)
|
|
—
|
|
|
4,462
|
|
||
Distributions payable
|
|
—
|
|
|
733
|
|
||
Current asset retirement obligation
|
|
5,905
|
|
|
2,341
|
|
||
Revenue and royalties payable
|
|
37,271
|
|
|
35,462
|
|
||
Wages and salaries payable
|
|
11,057
|
|
|
21,654
|
|
||
Accrued interest payable
|
|
21,064
|
|
|
19,517
|
|
||
Production and property taxes payable
|
|
15,340
|
|
|
24,292
|
|
||
Other current liabilities
|
|
17,466
|
|
|
5,133
|
|
||
Total current liabilities
|
|
1,354,200
|
|
|
318,006
|
|
||
|
|
|
|
|
||||
Liabilities subject to compromise (note 2)
|
|
1,879,176
|
|
|
—
|
|
||
|
|
|
|
|
||||
Credit agreement (note 9)
|
|
—
|
|
|
1,075,000
|
|
||
Senior notes, net (note 9)
|
|
—
|
|
|
1,752,194
|
|
||
Other long-term debt (note 9)
|
|
3,094
|
|
|
3,148
|
|
||
Total long-term debt (note 9)
|
|
3,094
|
|
|
2,830,342
|
|
||
Deferred income taxes
|
|
2,771
|
|
|
3,844
|
|
||
Asset retirement obligation (note 11)
|
|
252,589
|
|
|
252,037
|
|
||
Derivative instruments (note 5)
|
|
—
|
|
|
255
|
|
||
Other long-term liabilities
|
|
17,551
|
|
|
25,008
|
|
||
Total liabilities
|
|
3,509,381
|
|
|
3,429,492
|
|
||
Commitments and contingencies (note 13)
|
|
|
|
|
|
|
||
Equity:
|
|
|
|
|
||||
Series A cumulative redeemable preferred units, 8.0 million units issued and outstanding at December 31, 2016 and 2015 (note 14)
|
|
193,215
|
|
|
193,215
|
|
||
Series B perpetual convertible preferred units, 49.6 million and 48.8 million units issued and outstanding at December 31, 2016 and 2015, respectively (note 14)
|
|
359,611
|
|
|
353,471
|
|
||
Common units, 213.8 million and 213.5 million units issued and outstanding at December 31, 2016 and 2015, respectively (note 14)
|
|
45,158
|
|
|
852,114
|
|
||
Accumulated other comprehensive income (loss) (note 15)
|
|
1,032
|
|
|
(229
|
)
|
||
Total partners' equity
|
|
599,016
|
|
|
1,398,571
|
|
||
Noncontrolling interest
|
|
7,011
|
|
|
7,324
|
|
||
Total equity
|
|
606,027
|
|
|
1,405,895
|
|
||
Total liabilities and equity
|
|
$
|
4,115,408
|
|
|
$
|
4,835,387
|
|
|
|
Year Ended December 31,
|
||||||||||
Thousands of dollars, except per unit amounts
|
|
2016
|
|
2015
|
|
2014
|
||||||
Revenues and other income items:
|
|
|
|
|
|
|
||||||
Oil, natural gas and natural gas liquid sales
|
|
$
|
504,254
|
|
|
$
|
645,272
|
|
|
$
|
855,820
|
|
(Loss) gain on commodity derivative instruments, net (note 5)
|
|
(53,091
|
)
|
|
438,614
|
|
|
566,533
|
|
|||
Other revenue, net
|
|
17,842
|
|
|
24,829
|
|
|
7,616
|
|
|||
Total revenues and other income items
|
|
469,005
|
|
|
1,108,715
|
|
|
1,429,969
|
|
|||
Operating costs and expenses:
|
|
|
|
|
|
|
||||||
Operating costs
|
|
363,926
|
|
|
455,189
|
|
|
355,681
|
|
|||
Depletion, depreciation and amortization
|
|
318,528
|
|
|
460,047
|
|
|
291,709
|
|
|||
Impairments of oil and natural gas properties (note 7)
|
|
283,270
|
|
|
2,377,615
|
|
|
149,000
|
|
|||
Impairment of goodwill (note 7)
|
|
—
|
|
|
95,947
|
|
|
—
|
|
|||
General and administrative expenses
|
|
86,988
|
|
|
98,999
|
|
|
86,949
|
|
|||
Restructuring costs (note 18)
|
|
4,303
|
|
|
6,364
|
|
|
—
|
|
|||
(Gain) loss on sale of assets (note 4)
|
|
(11,203
|
)
|
|
(8,864
|
)
|
|
663
|
|
|||
Total operating costs and expenses
|
|
1,045,812
|
|
|
3,485,297
|
|
|
884,002
|
|
|||
Operating (loss) income
|
|
(576,807
|
)
|
|
(2,376,582
|
)
|
|
545,967
|
|
|||
Interest expense, net of capitalized interest (note 9)
|
|
148,214
|
|
|
203,027
|
|
|
126,960
|
|
|||
Loss (gain) on interest rate swaps (note 5)
|
|
2,021
|
|
|
2,691
|
|
|
(490
|
)
|
|||
Other income, net
|
|
(357
|
)
|
|
(814
|
)
|
|
(1,746
|
)
|
|||
Reorganization items, net (note 2)
|
|
91,156
|
|
|
—
|
|
|
—
|
|
|||
(Loss) income before taxes
|
|
(817,841
|
)
|
|
(2,581,486
|
)
|
|
421,243
|
|
|||
Income tax (benefit) expense
|
|
(1,708
|
)
|
|
1,527
|
|
|
(73
|
)
|
|||
Net (loss) income
|
|
(816,133
|
)
|
|
(2,583,013
|
)
|
|
421,316
|
|
|||
Less: Net (loss) income attributable to noncontrolling interest
|
|
(1,182
|
)
|
|
326
|
|
|
(17
|
)
|
|||
Net (loss) income attributable to the partnership
|
|
(814,951
|
)
|
|
(2,583,339
|
)
|
|
421,333
|
|
|||
Less: Distributions to Series A preferred unitholders
|
|
6,142
|
|
|
16,500
|
|
|
10,083
|
|
|||
Less: Non-cash distributions to Series B preferred unitholders
|
|
11,744
|
|
|
20,817
|
|
|
—
|
|
|||
Less: Net income attributable to participating units
|
|
—
|
|
|
—
|
|
|
5,348
|
|
|||
Less: Distributions on participating units in excess of earnings
|
|
—
|
|
|
1,731
|
|
|
—
|
|
|||
Net (loss) income used to calculate basic and diluted net (loss) income per unit
|
|
$
|
(832,837
|
)
|
|
$
|
(2,622,387
|
)
|
|
$
|
405,902
|
|
|
|
|
|
|
|
|
||||||
Basic net (loss) income per unit (note 14)
|
|
$
|
(3.90
|
)
|
|
$
|
(12.39
|
)
|
|
$
|
3.04
|
|
Diluted net (loss) income per unit (note 14)
|
|
$
|
(3.90
|
)
|
|
$
|
(12.39
|
)
|
|
$
|
3.02
|
|
|
|
|
|
|
|
|
||||||
Weighted average number of units used to calculate basic and diluted net (loss) income per unit (in thousands):
|
|
|
|
|
|
|
||||||
Basic
|
|
213,755
|
|
|
211,575
|
|
|
133,451
|
|
|||
Diluted
|
|
213,755
|
|
|
211,575
|
|
|
134,206
|
|
|
|
Year Ended December 31,
|
||||||||||
Thousands of dollars
|
|
2016
|
|
2015
|
|
2014
|
||||||
Net (loss) income
|
|
$
|
(816,133
|
)
|
|
$
|
(2,583,013
|
)
|
|
$
|
421,316
|
|
Other comprehensive income (loss), net of tax:
|
|
|
|
|
|
|
||||||
Change in fair value of available-for-sale securities (a)
|
|
986
|
|
|
(402
|
)
|
|
(189
|
)
|
|||
Pension and post-retirement benefits actuarial gain (loss) (b)
|
|
1,145
|
|
|
677
|
|
|
(473
|
)
|
|||
Total other comprehensive income (loss), net of tax
|
|
2,131
|
|
|
275
|
|
|
(662
|
)
|
|||
Total comprehensive (loss) income
|
|
(814,002
|
)
|
|
(2,582,738
|
)
|
|
420,654
|
|
|||
Less: Comprehensive (loss) income attributable to noncontrolling interest
|
|
(313
|
)
|
|
438
|
|
|
(287
|
)
|
|||
Comprehensive (loss) income attributable to the partnership
|
|
$
|
(813,689
|
)
|
|
$
|
(2,583,176
|
)
|
|
$
|
420,941
|
|
|
|
Year Ended December 31,
|
||||||||||
Thousands of dollars
|
|
2016
|
|
2015
|
|
2014
|
||||||
Cash flows from operating activities
|
|
|
|
|
|
|
||||||
Net (loss) income
|
|
$
|
(816,133
|
)
|
|
$
|
(2,583,013
|
)
|
|
$
|
421,316
|
|
Adjustments to reconcile to cash flow from operating activities:
|
|
|
|
|
|
|
||||||
Depletion, depreciation and amortization
|
|
318,528
|
|
|
460,047
|
|
|
291,709
|
|
|||
Impairments of oil and natural gas properties
|
|
283,270
|
|
|
2,377,615
|
|
|
149,000
|
|
|||
Impairment of goodwill
|
|
—
|
|
|
95,947
|
|
|
—
|
|
|||
Unit-based compensation expense
|
|
24,693
|
|
|
26,805
|
|
|
23,387
|
|
|||
Loss (gain) on derivative instruments
|
|
55,112
|
|
|
(435,923
|
)
|
|
(567,024
|
)
|
|||
Derivative instrument settlement receipts
|
|
172,199
|
|
|
494,234
|
|
|
26,806
|
|
|||
Income from equity affiliates, net
|
|
(593
|
)
|
|
(104
|
)
|
|
178
|
|
|||
Deferred income taxes
|
|
(1,074
|
)
|
|
1,269
|
|
|
(174
|
)
|
|||
(Gain) loss on sale of assets
|
|
(11,203
|
)
|
|
(8,864
|
)
|
|
663
|
|
|||
Non-cash reorganization items
|
|
47,632
|
|
|
—
|
|
|
—
|
|
|||
Amortization and write-off of debt issuance costs
|
|
24,959
|
|
|
22,768
|
|
|
7,950
|
|
|||
Other
|
|
5,340
|
|
|
(6,626
|
)
|
|
(1,746
|
)
|
|||
Changes in net assets and liabilities:
|
|
|
|
|
|
|
||||||
Accounts receivable and other assets
|
|
4,284
|
|
|
35,367
|
|
|
41,754
|
|
|||
Inventory
|
|
(72
|
)
|
|
2,801
|
|
|
163
|
|
|||
Net change in related party receivables and payables
|
|
1,414
|
|
|
188
|
|
|
142
|
|
|||
Accounts payable and other liabilities
|
|
66,104
|
|
|
(45,806
|
)
|
|
(36,369
|
)
|
|||
Net cash provided by operating activities
|
|
174,460
|
|
|
436,705
|
|
|
357,755
|
|
|||
Cash flows from investing activities
|
|
|
|
|
|
|
||||||
Property acquisitions, net of cash acquired (note 4)
|
|
(8,882
|
)
|
|
(18,201
|
)
|
|
(401,465
|
)
|
|||
Capital expenditures
|
|
(75,576
|
)
|
|
(269,350
|
)
|
|
(417,755
|
)
|
|||
Proceeds from sale of assets
|
|
12,705
|
|
|
14,547
|
|
|
499
|
|
|||
Proceeds from sale of available-for-sale securities
|
|
6,389
|
|
|
3,875
|
|
|
—
|
|
|||
Purchases of available-for-sale securities
|
|
(7,064
|
)
|
|
(4,021
|
)
|
|
—
|
|
|||
Other
|
|
—
|
|
|
(853
|
)
|
|
(18,283
|
)
|
|||
Net cash used in investing activities
|
|
(72,428
|
)
|
|
(274,003
|
)
|
|
(837,004
|
)
|
|||
Cash flows from financing activities
|
|
|
|
|
|
|
||||||
Proceeds from issuance of preferred units, net
|
|
—
|
|
|
337,238
|
|
|
193,215
|
|
|||
Proceeds from issuance of common units, net
|
|
—
|
|
|
3,008
|
|
|
277,613
|
|
|||
Distributions to preferred unitholders
|
|
(5,501
|
)
|
|
(16,502
|
)
|
|
(9,350
|
)
|
|||
Distributions to common unitholders
|
|
—
|
|
|
(126,188
|
)
|
|
(264,585
|
)
|
|||
Proceeds from issuance of long-term debt, net
|
|
38,260
|
|
|
1,378,338
|
|
|
2,457,600
|
|
|||
Repayments of long-term debt
|
|
(69,001
|
)
|
|
(1,711,500
|
)
|
|
(1,785,000
|
)
|
|||
Senior note redemption
|
|
—
|
|
|
—
|
|
|
(352,531
|
)
|
|||
Principal payments on capital lease obligations
|
|
(39
|
)
|
|
—
|
|
|
—
|
|
|||
Change in bank overdraft
|
|
(75
|
)
|
|
11
|
|
|
(2,434
|
)
|
|||
Debtor-in-possession debt issuance costs
|
|
(4,997
|
)
|
|
—
|
|
|
—
|
|
|||
Debt issuance costs
|
|
(19
|
)
|
|
(29,271
|
)
|
|
(25,109
|
)
|
|||
Net cash (used in) provided by financing activities
|
|
(41,372
|
)
|
|
(164,866
|
)
|
|
489,419
|
|
|||
Increase (decrease) in cash
|
|
60,660
|
|
|
(2,164
|
)
|
|
10,170
|
|
|||
Cash beginning of period
|
|
10,464
|
|
|
12,628
|
|
|
2,458
|
|
|||
Cash end of period
|
|
$
|
71,124
|
|
|
$
|
10,464
|
|
|
$
|
12,628
|
|
|
|
Units
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|||||||||||||||||
Thousands
|
|
Preferred Series A
|
|
Preferred Series B
|
|
Common
|
|
Preferred Series A
|
|
Preferred Series B
|
|
Common
|
|
Other Comprehensive Loss
|
|
Partner's Equity
|
|||||||||||||
Balance, December 31, 2013
|
|
—
|
|
|
—
|
|
|
119,170
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,989,820
|
|
|
$
|
—
|
|
|
$
|
1,989,820
|
|
Sales of Series A preferred units
|
|
8,000
|
|
|
—
|
|
|
—
|
|
|
193,215
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
193,215
|
|
|||||
Sales of common units
|
|
—
|
|
|
—
|
|
|
15,272
|
|
|
—
|
|
|
—
|
|
|
277,605
|
|
|
—
|
|
|
277,605
|
|
|||||
Distributions on Series A preferred units
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(10,083
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(10,083
|
)
|
|||||
Distributions on common units
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(260,958
|
)
|
|
—
|
|
|
(260,958
|
)
|
|||||
Common units issued for acquisitions
|
|
—
|
|
|
—
|
|
|
75,837
|
|
|
—
|
|
|
—
|
|
|
1,131,146
|
|
|
—
|
|
|
1,131,146
|
|
|||||
Common units issued under incentive plans
|
|
—
|
|
|
—
|
|
|
615
|
|
|
—
|
|
|
—
|
|
|
17,985
|
|
|
—
|
|
|
17,985
|
|
|||||
Distributions paid on unissued units under incentive plans
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,626
|
)
|
|
—
|
|
|
(3,626
|
)
|
|||||
Unit-based compensation
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,246
|
|
|
—
|
|
|
3,246
|
|
|||||
Net income attributable to the partnership
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10,083
|
|
|
—
|
|
|
411,250
|
|
|
—
|
|
|
421,333
|
|
|||||
Other comprehensive loss
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(392
|
)
|
|
(392
|
)
|
|||||
Balance, December 31, 2014
|
|
8,000
|
|
|
—
|
|
|
210,894
|
|
|
193,215
|
|
|
—
|
|
|
3,566,468
|
|
|
(392
|
)
|
|
3,759,291
|
|
|||||
Sales of Series B preferred units
|
|
—
|
|
|
46,667
|
|
|
—
|
|
|
—
|
|
|
337,238
|
|
|
—
|
|
|
—
|
|
|
337,238
|
|
|||||
Sales of common units
|
|
—
|
|
|
—
|
|
|
544
|
|
|
—
|
|
|
—
|
|
|
3,115
|
|
|
—
|
|
|
3,115
|
|
|||||
Distributions on Series A preferred units
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(16,500
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(16,500
|
)
|
|||||
Distributions paid-in-kind Series B preferred units
|
|
—
|
|
|
2,164
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Distributions paid-in-kind common units
|
|
—
|
|
|
—
|
|
|
448
|
|
|
—
|
|
|
(3,359
|
)
|
|
3,359
|
|
|
—
|
|
|
—
|
|
|||||
Distributions payable on Series B preferred units
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,225
|
)
|
|
—
|
|
|
—
|
|
|
(1,225
|
)
|
|||||
Distributions on common units
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(123,217
|
)
|
|
—
|
|
|
(123,217
|
)
|
|||||
Common units issued under incentive plans
|
|
—
|
|
|
—
|
|
|
1,595
|
|
|
—
|
|
|
—
|
|
|
28,500
|
|
|
—
|
|
|
28,500
|
|
|||||
Distributions paid on unissued units under incentive plans
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,971
|
)
|
|
—
|
|
|
(2,971
|
)
|
|||||
Unit-based compensation
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,484
|
)
|
|
—
|
|
|
(2,484
|
)
|
|||||
Net loss attributable to the partnership
|
|
—
|
|
|
—
|
|
|
—
|
|
|
16,500
|
|
|
20,817
|
|
|
(2,620,656
|
)
|
|
—
|
|
|
(2,583,339
|
)
|
|||||
Other comprehensive income
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
163
|
|
|
163
|
|
|||||
Balance, December 31, 2015
|
|
8,000
|
|
|
48,831
|
|
|
213,481
|
|
|
193,215
|
|
|
353,471
|
|
|
852,114
|
|
|
(229
|
)
|
|
1,398,571
|
|
|||||
Distributions on Series A preferred units
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6,142
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6,142
|
)
|
|||||
Distributions paid-in-kind Series B preferred units
|
|
—
|
|
|
819
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Distributions paid-in-kind common units
|
|
—
|
|
|
—
|
|
|
163
|
|
|
—
|
|
|
(1,225
|
)
|
|
1,225
|
|
|
—
|
|
|
—
|
|
|||||
Distributions payable on Series B preferred units
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4,379
|
)
|
|
—
|
|
|
—
|
|
|
(4,379
|
)
|
|||||
Common units issued under incentive plans
|
|
—
|
|
|
—
|
|
|
145
|
|
|
—
|
|
|
—
|
|
|
1,583
|
|
|
—
|
|
|
1,583
|
|
|||||
Unit-based compensation
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
23,073
|
|
|
—
|
|
|
23,073
|
|
|||||
Net loss attributable to the partnership
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6,142
|
|
|
11,744
|
|
|
(832,837
|
)
|
|
—
|
|
|
(814,951
|
)
|
|||||
Other comprehensive income
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,261
|
|
|
1,261
|
|
|||||
Balance, December 31, 2016
|
|
8,000
|
|
|
49,650
|
|
|
213,789
|
|
|
$
|
193,215
|
|
|
$
|
359,611
|
|
|
$
|
45,158
|
|
|
$
|
1,032
|
|
|
$
|
599,016
|
|
|
|
Year Ended
|
||
Thousands of dollars
|
|
December 31, 2016
|
||
Debt discounts/premiums and issuance costs
|
|
$
|
48,832
|
|
Advisory and professional fees
|
|
36,075
|
|
|
DIP Credit Agreement debt issuance costs
|
|
6,797
|
|
|
Other
|
|
(548
|
)
|
|
Reorganization items, net
|
|
$
|
91,156
|
|
|
|
As of
|
||
Thousands of dollars
|
|
December 31, 2016
|
||
Senior Unsecured Notes
|
|
$
|
1,155,000
|
|
Senior Secured Notes
|
|
650,000
|
|
|
Accrued interest payable
|
|
61,908
|
|
|
Accounts payable
|
|
5,294
|
|
|
Distributions payable
|
|
6,974
|
|
|
Total liabilities subject to compromise
|
|
$
|
1,879,176
|
|
|
|
As of December 31, 2015
|
||||||||||
|
|
Previously
|
|
Effect of Adoption of
|
|
|
||||||
Thousands of dollars
|
|
Reported
|
|
Accounting Principle
|
|
As Adjusted
|
||||||
Assets:
|
|
|
|
|
|
|
||||||
Other long-term assets
|
|
$
|
117,872
|
|
|
$
|
(37,025
|
)
|
|
$
|
80,847
|
|
Total assets
|
|
4,872,412
|
|
|
(37,025
|
)
|
|
4,835,387
|
|
|||
|
|
|
|
|
|
|
||||||
Liabilities:
|
|
|
|
|
|
|
||||||
Senior notes, net
|
|
$
|
1,789,219
|
|
|
$
|
(37,025
|
)
|
|
$
|
1,752,194
|
|
Total long-term debt
|
|
2,867,367
|
|
|
(37,025
|
)
|
|
2,830,342
|
|
|||
Total liabilities
|
|
3,466,517
|
|
|
(37,025
|
)
|
|
3,429,492
|
|
|||
Total liabilities and equity
|
|
4,872,412
|
|
|
(37,025
|
)
|
|
4,835,387
|
|
Thousands of dollars
|
|
|
||
Cash
|
|
$
|
5,121
|
|
Accounts and other receivables
|
|
113,398
|
|
|
Current derivative instrument assets
|
|
70,362
|
|
|
Prepaid expenses
|
|
3,123
|
|
|
Oil and gas properties
|
|
2,397,967
|
|
|
Non-oil and gas assets
|
|
17,866
|
|
|
Goodwill
|
|
95,947
|
|
|
Long-term derivative instrument assets
|
|
72,998
|
|
|
Other long-term assets
|
|
50,619
|
|
|
Accounts payable and accrued liabilities
|
|
(157,916
|
)
|
|
Current derivative instrument liabilities
|
|
(6,512
|
)
|
|
Current asset retirement obligation
|
|
(2,618
|
)
|
|
Credit facility debt
|
|
(790,000
|
)
|
|
Senior notes at fair value
|
|
(344,129
|
)
|
|
Long-term asset retirement obligation
|
|
(91,465
|
)
|
|
Long-term derivative instrument liabilities
|
|
(8,877
|
)
|
|
Other long-term liabilities
|
|
(10,277
|
)
|
|
Non-controlling interest
|
|
(7,173
|
)
|
|
|
|
$
|
1,408,434
|
|
|
|
Pro Forma Year Ended December 31,
|
||
Thousands of dollars, except per unit amounts
|
|
2014
|
||
Revenues
|
|
$
|
1,947,315
|
|
Net income attributable to the partnership
|
|
542,164
|
|
|
|
|
|
||
Net income per common unit:
|
|
|
||
Basic
|
|
$
|
2.56
|
|
Diluted
|
|
$
|
2.55
|
|
Balance sheet location, thousands of dollars
|
|
Oil Commodity Derivatives
|
|
Natural Gas Commodity Derivatives
|
|
Interest Rate Derivatives
|
|
Commodity Derivatives Netting (a)
|
|
Total Financial Instruments
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
As of December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Assets
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Current assets - derivative instruments
|
|
$
|
397,748
|
|
|
$
|
44,426
|
|
|
$
|
222
|
|
|
$
|
(2,769
|
)
|
|
$
|
439,627
|
|
Other long-term assets - derivative instruments
|
|
202,140
|
|
|
27,105
|
|
|
216
|
|
|
(2,697
|
)
|
|
226,764
|
|
|||||
Total assets
|
|
599,888
|
|
|
71,531
|
|
|
438
|
|
|
(5,466
|
)
|
|
666,391
|
|
|||||
Liabilities
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Current liabilities - derivative instruments
|
|
(15
|
)
|
|
(2,740
|
)
|
|
(4,476
|
)
|
|
2,769
|
|
|
(4,462
|
)
|
|||||
Long-term liabilities - derivative instruments
|
|
—
|
|
|
(2,865
|
)
|
|
(87
|
)
|
|
2,697
|
|
|
(255
|
)
|
|||||
Total liabilities
|
|
(15
|
)
|
|
(5,605
|
)
|
|
(4,563
|
)
|
|
5,466
|
|
|
(4,717
|
)
|
|||||
Net assets (liabilities)
|
|
$
|
599,873
|
|
|
$
|
65,926
|
|
|
$
|
(4,125
|
)
|
|
$
|
—
|
|
|
$
|
661,674
|
|
Location of gain (loss), thousands of dollars
|
|
Oil Commodity Derivatives (a)
|
|
Natural Gas Commodity Derivatives (a)
|
|
Interest Rate Derivatives (b)
|
|
Total Financial Instruments
|
||||||||
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
||||||||
Net loss
|
|
$
|
(43,344
|
)
|
|
$
|
(9,747
|
)
|
|
$
|
(2,021
|
)
|
|
$
|
(55,112
|
)
|
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
|
||||||||
Net gain (loss)
|
|
$
|
385,887
|
|
|
$
|
52,727
|
|
|
$
|
(2,691
|
)
|
|
$
|
435,923
|
|
Year Ended December 31, 2014
|
|
|
|
|
|
|
|
|
||||||||
Net gain
|
|
$
|
526,335
|
|
|
$
|
40,198
|
|
|
$
|
490
|
|
|
$
|
567,023
|
|
Thousands of dollars
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
|
|
|
|
|
|
|
|
|
||||||||
As of December 31, 2016
|
|
|
|
|
|
|
|
|
||||||||
Assets
|
|
|
|
|
|
|
|
|
||||||||
Available-for-sale securities
|
|
|
|
|
|
|
|
|
||||||||
Equities
|
|
$
|
1,492
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,492
|
|
Mutual funds
|
|
11,229
|
|
|
—
|
|
|
—
|
|
|
11,229
|
|
||||
Exchange traded funds
|
|
7,675
|
|
|
—
|
|
|
—
|
|
|
7,675
|
|
||||
Net assets
|
|
$
|
20,396
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
20,396
|
|
|
|
|
|
|
|
|
|
|
||||||||
As of December 31, 2015
|
|
|
|
|
|
|
|
|
||||||||
Assets (liabilities)
|
|
|
|
|
|
|
|
|
||||||||
Oil derivative instruments
|
|
|
|
|
|
|
|
|
||||||||
Oil swaps
|
|
$
|
—
|
|
|
$
|
552,552
|
|
|
$
|
—
|
|
|
$
|
552,552
|
|
Oil collars
|
|
—
|
|
|
—
|
|
|
29,737
|
|
|
29,737
|
|
||||
Oil puts
|
|
—
|
|
|
—
|
|
|
17,584
|
|
|
17,584
|
|
||||
Natural gas derivative instruments
|
|
|
|
|
|
|
|
|
||||||||
Natural gas swaps
|
|
—
|
|
|
54,182
|
|
|
—
|
|
|
54,182
|
|
||||
Natural gas collars
|
|
—
|
|
|
—
|
|
|
618
|
|
|
618
|
|
||||
Natural gas puts
|
|
—
|
|
|
—
|
|
|
11,126
|
|
|
11,126
|
|
||||
Interest rate swaps
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Interest rate swaps
|
|
—
|
|
|
(4,125
|
)
|
|
—
|
|
|
(4,125
|
)
|
||||
Available-for-sale securities
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Equities
|
|
2,524
|
|
|
—
|
|
|
—
|
|
|
2,524
|
|
||||
Mutual funds
|
|
11,190
|
|
|
—
|
|
|
—
|
|
|
11,190
|
|
||||
Exchange traded funds
|
|
4,977
|
|
|
—
|
|
|
—
|
|
|
4,977
|
|
||||
Net assets
|
|
$
|
18,691
|
|
|
$
|
602,609
|
|
|
$
|
59,065
|
|
|
$
|
680,365
|
|
|
|
Year End December 31,
|
||||||||||||||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||||||||||||||
Thousands of dollars
|
|
Oil
|
|
Natural Gas
|
|
Oil
|
|
Natural Gas
|
|
Oil
|
|
Natural Gas
|
||||||||||||
Assets (a):
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Beginning balance
|
|
$
|
47,321
|
|
|
$
|
11,744
|
|
|
$
|
61,410
|
|
|
$
|
19,892
|
|
|
$
|
8,957
|
|
|
$
|
1,848
|
|
Derivative instrument settlements (b)
|
|
26,834
|
|
|
2,580
|
|
|
44,647
|
|
|
16,815
|
|
|
4,094
|
|
|
815
|
|
||||||
(Loss) gain (b)(c)
|
|
(74,155
|
)
|
|
(14,324
|
)
|
|
(58,736
|
)
|
|
(24,963
|
)
|
|
37,189
|
|
|
5,357
|
|
||||||
Purchases (b)(d)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
11,170
|
|
|
11,872
|
|
||||||
Ending balance
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
47,321
|
|
|
$
|
11,744
|
|
|
$
|
61,410
|
|
|
$
|
19,892
|
|
|
|
Fair Value at
|
|
Valuation
|
|
|
|
|
||
Thousands of dollars
|
|
December 31, 2015
|
|
|
Technique
|
|
Unobservable Input
|
|
Range
|
|
Oil options
|
|
$
|
47,321
|
|
|
Option Pricing Model
|
|
Oil forward commodity prices
|
|
$37.04/Bbl - $47.79/Bbl
|
|
|
|
|
|
|
Oil volatility
|
|
32.24% - 44.95%
|
||
|
|
|
|
|
|
Own credit risk
|
|
5%
|
||
Natural gas options
|
|
11,744
|
|
|
Option Pricing Model
|
|
Gas forward commodity prices
|
|
$2.34/MMBtu - $2.99/MMBtu
|
|
|
|
|
|
|
|
Gas volatility
|
|
23.44% - 73.05%
|
||
|
|
|
|
|
|
Own credit risk
|
|
5%
|
||
Total
|
|
$
|
59,065
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
||||||
Thousands of dollars
|
|
2016
|
|
2015
|
||||
Debt issuance costs (Note 9)
|
|
$
|
—
|
|
|
$
|
22,142
|
|
Available-for-sale securities
|
|
20,396
|
|
|
18,691
|
|
||
Deposit for Jay Field net profit interest obligation
|
|
18,263
|
|
|
18,263
|
|
||
Property reclamation deposit
|
|
10,738
|
|
|
10,736
|
|
||
Other
|
|
14,449
|
|
|
11,015
|
|
||
Total
|
|
$
|
63,846
|
|
|
$
|
80,847
|
|
|
|
|
|
Gross
|
|
Gross
|
|
|
||||||||
Thousands of dollars
|
|
Cost Basis
|
|
Unrealized Gains
|
|
Unrealized Losses
|
|
Fair Value
|
||||||||
Available-for-sale securities:
|
|
|
|
|
|
|
|
|
||||||||
Equities
|
|
$
|
1,416
|
|
|
$
|
164
|
|
|
$
|
(88
|
)
|
|
$
|
1,492
|
|
Mutual funds
|
|
12,838
|
|
|
175
|
|
|
(1,784
|
)
|
|
11,229
|
|
||||
Exchange traded funds
|
|
5,545
|
|
|
2,158
|
|
|
(28
|
)
|
|
7,675
|
|
||||
Total available-for-sale securities
|
|
$
|
19,799
|
|
|
$
|
2,497
|
|
|
$
|
(1,900
|
)
|
|
$
|
20,396
|
|
|
|
|
|
Gross
|
|
Gross
|
|
|
||||||||
Thousands of dollars
|
|
Cost Basis
|
|
Unrealized Gains
|
|
Unrealized Losses
|
|
Fair Value
|
||||||||
Available-for-sale securities:
|
|
|
|
|
|
|
|
|
||||||||
Equities
|
|
$
|
2,591
|
|
|
$
|
141
|
|
|
$
|
(208
|
)
|
|
$
|
2,524
|
|
Mutual funds
|
|
13,276
|
|
|
1,737
|
|
|
(3,823
|
)
|
|
11,190
|
|
||||
Exchange traded funds
|
|
3,721
|
|
|
1,494
|
|
|
(238
|
)
|
|
4,977
|
|
||||
Total available-for-sale securities
|
|
$
|
19,588
|
|
|
$
|
3,372
|
|
|
$
|
(4,269
|
)
|
|
$
|
18,691
|
|
|
|
As of December 31,
|
||||||
Thousands of dollars
|
|
2016
|
|
2015
|
||||
Credit Agreement
|
|
$
|
1,198,259
|
|
|
$
|
1,229,000
|
|
Promissory note
|
|
2,938
|
|
|
2,938
|
|
||
Senior Secured Notes
|
|
650,000
|
|
|
650,000
|
|
||
2020 Senior Notes
|
|
305,000
|
|
|
305,000
|
|
||
2022 Senior Notes
|
|
850,000
|
|
|
850,000
|
|
||
Unamortized debt issuance costs and net discount/premium on Senior Notes (a)
|
|
—
|
|
|
(52,806
|
)
|
||
Capital lease obligations
|
|
156
|
|
|
210
|
|
||
Total debt
|
|
3,006,353
|
|
|
2,984,342
|
|
||
Less: Current portion of long-term debt
|
|
(1,198,259
|
)
|
|
(154,000
|
)
|
||
Less: Amounts reclassified to liabilities subject to compromise
|
|
(1,805,000
|
)
|
|
—
|
|
||
Total long-term debt
|
|
$
|
3,094
|
|
|
$
|
2,830,342
|
|
|
|
Year Ended December 31,
|
||||||||||
Thousands of dollars
|
|
2016
|
|
2015
|
|
2014
|
||||||
Credit Agreement (including commitment fees) and other long-term debt
|
|
$
|
64,713
|
|
|
$
|
41,254
|
|
|
$
|
23,788
|
|
Senior Secured Notes (a)
|
|
22,547
|
|
|
43,758
|
|
|
—
|
|
|||
Senior Unsecured Notes (a)
|
|
34,966
|
|
|
93,244
|
|
|
95,662
|
|
|||
Amortization of discount/premium and deferred issuance costs (b)
|
|
26,137
|
|
|
24,926
|
|
|
7,836
|
|
|||
Capitalized interest
|
|
(149
|
)
|
|
(155
|
)
|
|
(326
|
)
|
|||
Total
|
|
$
|
148,214
|
|
|
$
|
203,027
|
|
|
$
|
126,960
|
|
Cash paid for interest
|
|
$
|
62,056
|
|
|
$
|
181,873
|
|
|
$
|
119,488
|
|
(1)
|
a disposition of all or substantially all the assets of the guarantor subsidiary (including by way or merger or consolidation), to a third person, provided the disposition complies with the applicable indenture,
|
(2)
|
a disposition of the capital stock of the guarantor subsidiary to a third person, if the disposition complies with the applicable indenture and as a result the guarantor subsidiary ceases to be our subsidiary,
|
(3)
|
the designation by us of the guarantor subsidiary as an Unrestricted Subsidiary in accordance with the applicable indenture,
|
(4)
|
legal or covenant defeasance of such series of Senior Notes or satisfaction and discharge of the related indenture,
|
(5)
|
the liquidation or dissolution of the guarantor subsidiary, provided no default under the applicable indenture exists, or
|
(6)
|
the guarantor subsidiary ceases both (a) to guarantee any other indebtedness of ours or any other guarantor subsidiary and (b) to be an obligor under any bank credit facility.
|
|
|
Year Ended December 31,
|
||||||
Thousands of dollars
|
|
2016
|
|
2015
|
||||
Carrying amount, beginning of period
|
|
$
|
254,378
|
|
|
$
|
238,411
|
|
Liabilities added from acquisitions
|
|
78
|
|
|
796
|
|
||
Liabilities incurred from drilling
|
|
224
|
|
|
2,268
|
|
||
Liabilities settled
|
|
(3,162
|
)
|
|
(7,744
|
)
|
||
Liabilities related to divested properties
|
|
(8,380
|
)
|
|
(261
|
)
|
||
Revision of estimates
|
|
(2,362
|
)
|
|
3,954
|
|
||
Accretion expense
|
|
17,718
|
|
|
16,954
|
|
||
Carrying amount, end of period
|
|
258,494
|
|
|
254,378
|
|
||
Less: Current portion of ARO
|
|
(5,905
|
)
|
|
(2,341
|
)
|
||
Non-current portion of ARO
|
|
$
|
252,589
|
|
|
$
|
252,037
|
|
|
|
December 31, 2016
|
|
December 31, 2015
|
||||||||||||
Thousands of dollars
|
|
Pension Benefits
|
|
Postretirement Benefits
|
|
Pension Benefits
|
|
Postretirement Benefits
|
||||||||
Projected benefit obligation
|
|
$
|
22,227
|
|
|
$
|
1,414
|
|
|
$
|
25,320
|
|
|
$
|
3,971
|
|
Accumulated benefit obligation
|
|
21,917
|
|
|
1,414
|
|
|
24,424
|
|
|
3,971
|
|
||||
Fair value of plan assets
|
|
15,955
|
|
|
841
|
|
|
20,022
|
|
|
1,468
|
|
|
|
Year Ended December 31, 2016
|
|
Year Ended December 31, 2015
|
||||||||||||
Thousands of dollars
|
|
Pension Benefits
|
|
Postretirement Benefits
|
|
Pension Benefits
|
|
Postretirement Benefits
|
||||||||
Change in Benefit Obligation
|
|
|
|
|
|
|
|
|
||||||||
Benefit obligation at beginning of year
|
|
$
|
25,320
|
|
|
$
|
3,971
|
|
|
$
|
27,829
|
|
|
$
|
4,240
|
|
Service cost
|
|
165
|
|
|
31
|
|
|
271
|
|
|
34
|
|
||||
Interest cost
|
|
905
|
|
|
121
|
|
|
1,014
|
|
|
155
|
|
||||
Plan participant contributions
|
|
—
|
|
|
31
|
|
|
—
|
|
|
28
|
|
||||
Actuarial (gain) loss
|
|
221
|
|
|
(24
|
)
|
|
(2,360
|
)
|
|
(333
|
)
|
||||
Benefits paid
|
|
(1,536
|
)
|
|
(183
|
)
|
|
(1,434
|
)
|
|
(153
|
)
|
||||
Estimated lump sums (early retirement incentive program)
|
|
(3,500
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Special termination benefit
|
|
376
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Effect of curtailment
|
|
276
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Effect of change to participant contributions
|
|
—
|
|
|
(884
|
)
|
|
—
|
|
|
—
|
|
||||
Effect of early retirement incentive program
|
|
—
|
|
|
(1,053
|
)
|
|
—
|
|
|
—
|
|
||||
Effect of settlements
|
|
—
|
|
|
(596
|
)
|
|
—
|
|
|
—
|
|
||||
Benefit obligation at end of year
|
|
22,227
|
|
|
1,414
|
|
|
25,320
|
|
|
3,971
|
|
||||
Change in Plan Assets
|
|
|
|
|
|
|
|
|
||||||||
Fair value of plan assets at beginning of year
|
|
20,022
|
|
|
1,468
|
|
|
21,219
|
|
|
1,527
|
|
||||
Actual return on plan assets
|
|
969
|
|
|
(15
|
)
|
|
(163
|
)
|
|
(63
|
)
|
||||
Employer contributions
|
|
—
|
|
|
136
|
|
|
400
|
|
|
129
|
|
||||
Plan participant contributions
|
|
—
|
|
|
31
|
|
|
—
|
|
|
28
|
|
||||
Benefits paid
|
|
(1,536
|
)
|
|
(183
|
)
|
|
(1,434
|
)
|
|
(153
|
)
|
||||
Estimated lump sums (early retirement incentive program)
|
|
(3,500
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Effects of settlements
|
|
—
|
|
|
(596
|
)
|
|
—
|
|
|
—
|
|
||||
Fair value of plan assets at end of year
|
|
15,955
|
|
|
841
|
|
|
20,022
|
|
|
1,468
|
|
||||
Underfunded status at end of year
|
|
$
|
(6,272
|
)
|
|
$
|
(573
|
)
|
|
(5,298
|
)
|
|
(2,503
|
)
|
|
|
December 31, 2016
|
|
December 31, 2015
|
||||||||||||
Thousands of dollars
|
|
Pension Benefits
|
|
Postretirement Benefits
|
|
Pension Benefits
|
|
Postretirement Benefits
|
||||||||
Long-term liabilities
|
|
$
|
6,272
|
|
|
$
|
573
|
|
|
$
|
5,298
|
|
|
$
|
2,503
|
|
|
|
Year Ended December 31, 2016
|
|
Year Ended December 31, 2015
|
||||||||||||
Thousands of dollars
|
|
Pension Benefits
|
|
Postretirement Benefits
|
|
Pension Benefits
|
|
Postretirement Benefits
|
||||||||
Service cost
|
|
$
|
165
|
|
|
$
|
31
|
|
|
$
|
271
|
|
|
$
|
34
|
|
Interest cost
|
|
905
|
|
|
121
|
|
|
1,014
|
|
|
155
|
|
||||
Expected return on plan assets
|
|
(1,146
|
)
|
|
(74
|
)
|
|
(1,342
|
)
|
|
(99
|
)
|
||||
Special termination benefit
|
|
376
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Effect of curtailment
|
|
276
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Effect of settlement
|
|
245
|
|
|
57
|
|
|
—
|
|
|
—
|
|
||||
Amortization of prior service cost/(credit)
|
|
—
|
|
|
(41
|
)
|
|
—
|
|
|
—
|
|
||||
Net periodic benefit costs
|
|
$
|
821
|
|
|
$
|
94
|
|
|
$
|
(57
|
)
|
|
$
|
90
|
|
|
|
Year Ended December 31, 2016
|
|
Year Ended December 31, 2015
|
||||||||||||
Thousands of dollars
|
|
Pension Benefits
|
|
Postretirement Benefits
|
|
Pension Benefits
|
|
Postretirement Benefits
|
||||||||
Prior service credit
|
|
$
|
—
|
|
|
$
|
(1,936
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
Net actuarial (gain) loss:
|
|
|
|
|
|
|
|
|
||||||||
Liability loss (gain) due to assumption change
|
|
673
|
|
|
322
|
|
|
(2,045
|
)
|
|
(220
|
)
|
||||
Liability (gain) loss due to participant experience
|
|
(452
|
)
|
|
(346
|
)
|
|
(315
|
)
|
|
(113
|
)
|
||||
Loss due to settlement
|
|
(245
|
)
|
|
(57
|
)
|
|
—
|
|
|
—
|
|
||||
Asset return loss
|
|
178
|
|
|
89
|
|
|
1,505
|
|
|
162
|
|
||||
Amortization of prior service credit
|
|
—
|
|
|
41
|
|
|
—
|
|
|
—
|
|
||||
Net actuarial (gain) loss
|
|
154
|
|
|
49
|
|
|
(855
|
)
|
|
(171
|
)
|
||||
Total
|
|
$
|
154
|
|
|
$
|
(1,887
|
)
|
|
$
|
(855
|
)
|
|
$
|
(171
|
)
|
Thousands of dollars
|
|
Pension Benefits
|
|
Postretirement Benefits
|
||||
2017
|
|
$
|
1,530
|
|
|
$
|
81
|
|
2018
|
|
1,510
|
|
|
89
|
|
||
2019
|
|
1,490
|
|
|
84
|
|
||
2020
|
|
1,480
|
|
|
85
|
|
||
2021
|
|
1,460
|
|
|
93
|
|
||
2022-2026
|
|
7,150
|
|
|
340
|
|
|
|
December 31, 2016
|
|
December 31, 2015
|
||||||||
|
|
Pension Benefits
|
|
Postretirement Benefits
|
|
Pension Benefits
|
|
Postretirement Benefits
|
||||
Discount rate
|
|
3.85
|
%
|
|
3.85
|
%
|
|
4.10
|
%
|
|
4.10
|
%
|
Rate of compensation increase
|
|
3.00
|
%
|
|
N/A
|
|
|
3.00
|
%
|
|
N/A
|
|
Health care cost trend rate:
|
|
|
|
|
|
|
|
|
||||
Pre - 65 rate
|
|
N/A
|
|
|
7.00
|
%
|
|
N/A
|
|
|
7.00
|
%
|
Post - 65 rate
|
|
N/A
|
|
|
7.00
|
%
|
|
N/A
|
|
|
7.00
|
%
|
Expected long-term rates of return on plan assets
|
|
6.00
|
%
|
|
6.00
|
%
|
|
6.75
|
%
|
|
6.75
|
%
|
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)
|
|
N/A
|
|
|
4.50
|
%
|
|
N/A
|
|
|
4.50
|
%
|
Year that the rate reaches the ultimate trend rate
|
|
N/A
|
|
|
2025
|
|
|
N/A
|
|
|
2023
|
|
|
|
Year Ended December 31, 2016
|
|
Year Ended December 31, 2015
|
||||||||
|
|
Pension Benefits
|
|
Postretirement Benefits
|
|
Pension Benefits
|
|
Postretirement Benefits
|
||||
Discount rate
|
|
3.81
|
%
|
|
3.81
|
%
|
|
3.75
|
%
|
|
3.75
|
%
|
Expected long-term return on plan assets
|
|
6.75
|
%
|
|
6.75
|
%
|
|
6.50
|
%
|
|
6.50
|
%
|
Rate of compensation increase
|
|
3.00
|
%
|
|
N/A
|
|
|
3.00
|
%
|
|
N/A
|
|
|
|
Payments Due by Year
|
|
|
|
|
||||||||||||||||||||||
Thousands of dollars
|
|
2017
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
Thereafter
|
|
Total
|
||||||||||||||
Operating leases
|
|
$
|
4,866
|
|
|
$
|
3,467
|
|
|
$
|
2,570
|
|
|
$
|
2,476
|
|
|
$
|
2,460
|
|
|
$
|
5,714
|
|
|
$
|
21,553
|
|
|
|
Year Ended December 31,
|
||||||||||
Thousands, except per unit amounts
|
|
2016
|
|
2015
|
|
2014
|
||||||
Net (loss) income attributable to the partnership
|
|
$
|
(814,951
|
)
|
|
$
|
(2,583,339
|
)
|
|
$
|
421,333
|
|
Less:
|
|
|
|
|
|
|
||||||
Net income attributable to participating units
|
|
—
|
|
|
—
|
|
|
5,348
|
|
|||
Distributions on participating units in excess of earnings
|
|
—
|
|
|
1,731
|
|
|
—
|
|
|||
Distributions to Series A preferred unitholders
|
|
6,142
|
|
|
16,500
|
|
|
10,083
|
|
|||
Non-cash distributions to Series B preferred unitholders
|
|
11,744
|
|
|
20,817
|
|
|
—
|
|
|||
Net (loss) income used to calculate basic and diluted net (loss) income per unit
|
|
$
|
(832,837
|
)
|
|
$
|
(2,622,387
|
)
|
|
$
|
405,902
|
|
|
|
|
|
|
|
|
||||||
Weighted average number of units used to calculate basic and diluted net (loss) income per unit:
|
|
|
|
|
|
|
||||||
Common Units
|
|
213,755
|
|
|
211,575
|
|
|
133,451
|
|
|||
Dilutive units (a)
|
|
—
|
|
|
—
|
|
|
755
|
|
|||
Denominator for diluted net (loss) income per unit
|
|
213,755
|
|
|
211,575
|
|
|
134,206
|
|
|||
|
|
|
|
|
|
|
||||||
Net (loss) income per common unit
|
|
|
|
|
|
|
||||||
Basic
|
|
$
|
(3.90
|
)
|
|
$
|
(12.39
|
)
|
|
$
|
3.04
|
|
Diluted
|
|
$
|
(3.90
|
)
|
|
$
|
(12.39
|
)
|
|
$
|
3.02
|
|
|
|
Gain (loss) on
|
||||||||||
Thousands of dollars
|
|
Available-For-Sale Securities
|
|
Pension and Postretirement Benefits
|
|
Total
|
||||||
Accumulated comprehensive loss as of December 31, 2014
|
|
$
|
(112
|
)
|
|
$
|
(280
|
)
|
|
$
|
(392
|
)
|
Other comprehensive (loss) income before reclassification
|
|
(267
|
)
|
|
677
|
|
|
410
|
|
|||
Amounts reclassified from accumulated other comprehensive (loss) income (a)
|
|
(135
|
)
|
|
—
|
|
|
(135
|
)
|
|||
Net current period other comprehensive (loss) income
|
|
(402
|
)
|
|
677
|
|
|
275
|
|
|||
|
|
|
|
|
|
|
||||||
Accumulated comprehensive (loss) income as of December 31, 2015
|
|
(514
|
)
|
|
397
|
|
|
(117
|
)
|
|||
Less: Accumulated comprehensive (loss) income attributable to non-controlling interest
|
|
(164
|
)
|
|
276
|
|
|
112
|
|
|||
Accumulated comprehensive (loss) income attributable to the Partnership as of December 31, 2015
|
|
(350
|
)
|
|
121
|
|
|
(229
|
)
|
|||
|
|
|
|
|
|
|
||||||
Other comprehensive income before reclassification
|
|
1,450
|
|
|
1,145
|
|
|
2,595
|
|
|||
Amounts reclassified from accumulated other comprehensive loss (a)
|
|
(464
|
)
|
|
—
|
|
|
(464
|
)
|
|||
Net current period other comprehensive income
|
|
986
|
|
|
1,145
|
|
|
2,131
|
|
|||
|
|
|
|
|
|
|
||||||
Accumulated comprehensive income as of December 31, 2016
|
|
636
|
|
|
1,266
|
|
|
1,902
|
|
|||
Less: Accumulated comprehensive income attributable to non-controlling interest
|
|
402
|
|
|
468
|
|
|
870
|
|
|||
Accumulated comprehensive income attributable to the Partnership as of December 31, 2016
|
|
$
|
234
|
|
|
$
|
798
|
|
|
$
|
1,032
|
|
|
|
Year Ended December 31,
|
|||||||||||||||||||
|
|
2016
|
|
2015
|
|
2014
|
|||||||||||||||
|
|
Number
|
|
Weighted
|
|
Number
|
|
Weighted
|
|
Number
|
|
Weighted
|
|||||||||
|
|
of
|
|
Average
|
|
of
|
|
Average
|
|
of
|
|
Average
|
|||||||||
Thousands, except per unit amounts
|
|
RPUs
|
|
Fair Value
|
|
RPUs
|
|
Fair Value
|
|
RPUs
|
|
Fair Value
|
|||||||||
Outstanding, beginning of period
|
|
3,038
|
|
|
$
|
7.90
|
|
|
957
|
|
|
$
|
20.98
|
|
|
896
|
|
|
$
|
21.05
|
|
Granted
|
|
7,000
|
|
|
0.68
|
|
|
4,739
|
|
|
6.46
|
|
|
1,025
|
|
|
20.21
|
|
|||
Vested (a)
|
|
(146
|
)
|
|
7.53
|
|
|
(2,012
|
)
|
|
10.63
|
|
|
(906
|
)
|
|
20.22
|
|
|||
Canceled
|
|
(9,892
|
)
|
|
2.74
|
|
|
(646
|
)
|
|
8.24
|
|
|
(58
|
)
|
|
20.36
|
|
|||
Outstanding, end of period
|
|
—
|
|
|
$
|
—
|
|
|
3,038
|
|
|
$
|
7.90
|
|
|
957
|
|
|
$
|
20.98
|
|
|
|
Year Ended December 31,
|
|||||||||||||||||||
|
|
2016
|
|
2015
|
|
2014
|
|||||||||||||||
|
|
Number
|
|
Weighted
|
|
Number
|
|
Weighted
|
|
Number
|
|
Weighted
|
|||||||||
|
|
of
|
|
Average
|
|
of
|
|
Average
|
|
of
|
|
Average
|
|||||||||
Thousands, except per unit amounts
|
|
Units
|
|
Fair Value
|
|
Units
|
|
Fair Value
|
|
Units
|
|
Fair Value
|
|||||||||
Outstanding, beginning of period
|
|
201
|
|
|
$
|
9.42
|
|
|
78
|
|
|
$
|
20.44
|
|
|
67
|
|
|
$
|
20.69
|
|
Granted
|
|
631
|
|
|
0.68
|
|
|
160
|
|
|
6.56
|
|
|
43
|
|
|
20.29
|
|
|||
Vested
|
|
(80
|
)
|
|
10.89
|
|
|
(37
|
)
|
|
20.35
|
|
|
(32
|
)
|
|
20.77
|
|
|||
Canceled
|
|
(752
|
)
|
|
1.89
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Outstanding, end of period
|
|
—
|
|
|
$
|
—
|
|
|
201
|
|
|
$
|
9.42
|
|
|
78
|
|
|
$
|
20.44
|
|
|
|
Year Ended December 31,
|
||||||
Thousands of dollars
|
|
2016
|
|
2015
|
||||
Severance payments
|
|
$
|
3,585
|
|
|
$
|
4,768
|
|
Unit-based compensation expense
|
|
554
|
|
|
1,343
|
|
||
Other termination costs
|
|
164
|
|
|
253
|
|
||
Total
|
|
$
|
4,303
|
|
|
$
|
6,364
|
|
|
|
Year Ended December 31,
|
||||||||||
Thousands of dollars
|
|
2016
|
|
2015
|
|
2014
|
||||||
Property acquisition costs
|
|
|
|
|
|
|
||||||
Proved
|
|
$
|
972
|
|
|
$
|
7,943
|
|
|
$
|
1,707,528
|
|
Unproved (a)
|
|
4,296
|
|
|
2,593
|
|
|
734,603
|
|
|||
Pipelines and processing facilities
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Asset retirement costs
|
|
—
|
|
|
492
|
|
|
91,097
|
|
|||
Development costs
|
|
60,582
|
|
|
201,859
|
|
|
388,807
|
|
|||
Asset retirement costs - development
|
|
224
|
|
|
2,268
|
|
|
4,020
|
|
|||
Total costs incurred
|
|
$
|
66,074
|
|
|
$
|
215,155
|
|
|
$
|
2,926,055
|
|
|
|
December 31,
|
||||||
Thousands of dollars
|
|
2016
|
|
2015
|
||||
Proved properties and related producing assets
|
|
$
|
6,535,209
|
|
|
$
|
6,502,029
|
|
Pipelines and processing facilities
|
|
316,248
|
|
|
342,224
|
|
||
Unproved properties (a)
|
|
1,055,679
|
|
|
1,053,834
|
|
||
Accumulated depreciation, depletion and amortization
|
|
(4,627,441
|
)
|
|
(4,113,741
|
)
|
||
Net capitalized costs
|
|
$
|
3,279,695
|
|
|
$
|
3,784,346
|
|
|
|
Year Ended December 31,
|
||||||||||
Thousands of dollars
|
|
2016
|
|
2015
|
|
2014
|
||||||
Oil, NGL and natural gas sales
|
|
$
|
504,254
|
|
|
$
|
645,272
|
|
|
$
|
855,820
|
|
(Loss) gain on commodity derivative instruments, net
|
|
(53,091
|
)
|
|
438,614
|
|
|
566,533
|
|
|||
Operating costs
|
|
(350,015
|
)
|
|
(440,533
|
)
|
|
(352,906
|
)
|
|||
Depletion, depreciation and amortization
|
|
(303,298
|
)
|
|
(448,791
|
)
|
|
(288,503
|
)
|
|||
Impairment of oil and natural gas properties
|
|
(283,270
|
)
|
|
(2,377,615
|
)
|
|
(149,000
|
)
|
|||
Income tax benefit (expense)
|
|
1,117
|
|
|
(214
|
)
|
|
91
|
|
|||
Results of operations from producing activities (a)
|
|
$
|
(484,303
|
)
|
|
$
|
(2,183,267
|
)
|
|
$
|
632,035
|
|
|
|
|
Oil
(in MBbls) |
|
NGLs
(in MBbls) |
|
Natural Gas
(in MMcf) |
|
Total
(MBoe) |
||||
Estimated Proved Reserves
|
|
|
|
|
|
|
|
|
|||||
December 31, 2013
|
|
113,209
|
|
|
15,690
|
|
|
512,233
|
|
|
214,271
|
|
|
|
Revision of previous estimates
|
|
(20,005
|
)
|
|
(5,798
|
)
|
|
(1,589
|
)
|
|
(26,067
|
)
|
|
Purchase of previous reserves in-place
|
|
82,394
|
|
|
14,399
|
|
|
211,317
|
|
|
132,012
|
|
|
Sale of reserves in-place
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Extensions, discoveries and other
|
|
7,172
|
|
|
651
|
|
|
8,297
|
|
|
9,206
|
|
|
Production
|
|
(7,931
|
)
|
|
(1,157
|
)
|
|
(30,159
|
)
|
|
(14,114
|
)
|
December 31, 2014
|
|
174,839
|
|
|
23,785
|
|
|
700,099
|
|
|
315,308
|
|
|
|
Revision of previous estimates
|
|
(44,387
|
)
|
|
(3,553
|
)
|
|
(141,618
|
)
|
|
(71,544
|
)
|
|
Purchase of previous reserves in-place
|
|
334
|
|
|
11
|
|
|
2,268
|
|
|
723
|
|
|
Sale of reserves in-place
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Extensions, discoveries and other
|
|
9,538
|
|
|
1,322
|
|
|
24,293
|
|
|
14,910
|
|
|
Production
|
|
(11,190
|
)
|
|
(1,953
|
)
|
|
(41,876
|
)
|
|
(20,123
|
)
|
December 31, 2015
|
|
129,134
|
|
|
19,612
|
|
|
543,166
|
|
|
239,274
|
|
|
|
Revision of previous estimates
|
|
(21,957
|
)
|
|
(1,385
|
)
|
|
(66,304
|
)
|
|
(34,392
|
)
|
|
Purchase of previous reserves in-place
|
|
49
|
|
|
4
|
|
|
7
|
|
|
54
|
|
|
Sale of reserves in-place
|
|
(918
|
)
|
|
(62
|
)
|
|
(6,051
|
)
|
|
(1,989
|
)
|
|
Extensions, discoveries and other
|
|
15,880
|
|
|
2,697
|
|
|
12,091
|
|
|
20,592
|
|
|
Production
|
|
(9,504
|
)
|
|
(1,984
|
)
|
|
(40,747
|
)
|
|
(18,279
|
)
|
December 31, 2016
|
|
112,684
|
|
|
18,882
|
|
|
442,162
|
|
|
205,260
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Proved developed reserves
|
|
|
|
|
|
|
|
|
|||||
|
December 31, 2014
|
|
126,495
|
|
|
16,485
|
|
|
604,723
|
|
|
243,768
|
|
|
December 31, 2015
|
|
95,096
|
|
|
13,759
|
|
|
498,606
|
|
|
191,956
|
|
|
December 31, 2016
|
|
71,844
|
|
|
11,001
|
|
|
414,498
|
|
|
151,928
|
|
|
|
|
|
|
|
|
|
|
|
||||
Proved undeveloped reserves
|
|
|
|
|
|
|
|
|
|||||
|
December 31, 2014
|
|
48,344
|
|
|
7,300
|
|
|
95,376
|
|
|
71,540
|
|
|
December 31, 2015
|
|
34,038
|
|
|
5,853
|
|
|
44,560
|
|
|
47,318
|
|
|
December 31, 2016
|
|
40,840
|
|
|
7,881
|
|
|
27,664
|
|
|
53,332
|
|
|
|
December 31,
|
||||||||||
Thousands of dollars
|
|
2016
|
|
2015
|
|
2014
|
||||||
Future cash inflows
|
|
$
|
5,837,660
|
|
|
$
|
7,910,652
|
|
|
$
|
20,014,316
|
|
Future development costs
|
|
(1,134,465
|
)
|
|
(1,070,048
|
)
|
|
(1,904,400
|
)
|
|||
Future production expense
|
|
(3,224,728
|
)
|
|
(4,394,562
|
)
|
|
(8,445,646
|
)
|
|||
Future net cash flows
|
|
1,478,467
|
|
|
2,446,042
|
|
|
9,664,270
|
|
|||
Discounted at 10% per year
|
|
(674,808
|
)
|
|
(1,165,229
|
)
|
|
(5,160,166
|
)
|
|||
Standardized measure of discounted future net cash flows
|
|
$
|
803,659
|
|
|
$
|
1,280,813
|
|
|
$
|
4,504,104
|
|
1.
|
An estimate was made of the quantity of proved reserves and the future periods in which they are expected to be produced based on year-end economic conditions.
|
2.
|
In accordance with SEC guidelines, the reserve engineers’ estimates of future net revenues from our estimated proved properties and the present value thereof are made using unweighted average first-day-of-the-month oil and gas sales prices and are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. Representative unweighted average first-day-of-the-month market prices for the reserve reports for the year ended
December 31, 2016
were
$42.75
per Bbl of oil and
$2.48
per MMBtu of natural gas, compared to
$50.28
per Bbl of oil and
$2.59
per MMBtu of natural gas in
2015
. Unweighted average first-day-of-the-month market prices for the reserve reports for the year ended
December 31, 2014
were
$94.99
per Bbl of oil and
$4.35
per MMBtu of natural gas.
|
3.
|
The future gross revenue streams were reduced by estimated future operating costs (including production and ad valorem taxes) and future development and abandonment costs, all of which were based on current costs. Future net cash flows assume no future income tax expense as we are essentially a non-taxable entity except for four tax-paying corporations whose future income tax liabilities on a discounted basis are insignificant.
|
|
|
Year Ended December 31,
|
||||||||||
Thousands of dollars
|
|
2016
|
|
2015
|
|
2014
|
||||||
Beginning balance
|
|
$
|
1,280,813
|
|
|
$
|
4,504,104
|
|
|
$
|
3,225,848
|
|
Sales, net of production expense
|
|
(154,238
|
)
|
|
(204,739
|
)
|
|
(500,139
|
)
|
|||
Net change in sales and transfer prices, net of production expense
|
|
(457,339
|
)
|
|
(3,787,527
|
)
|
|
(29,497
|
)
|
|||
Previously estimated development costs incurred during year
|
|
69,589
|
|
|
501,097
|
|
|
315,792
|
|
|||
Changes in estimated future development costs
|
|
31,790
|
|
|
106,577
|
|
|
(68,949
|
)
|
|||
Extensions, discoveries and improved recovery, net of costs
|
|
54,562
|
|
|
86,726
|
|
|
175,335
|
|
|||
Purchase of reserves in place
|
|
972
|
|
|
7,943
|
|
|
1,707,528
|
|
|||
Sale of reserves in place
|
|
(8,513
|
)
|
|
—
|
|
|
—
|
|
|||
Revision of quantity estimates and timing of estimated production
|
|
(142,058
|
)
|
|
(383,778
|
)
|
|
(644,399
|
)
|
|||
Accretion of discount
|
|
128,081
|
|
|
450,410
|
|
|
322,585
|
|
|||
Ending balance
|
|
$
|
803,659
|
|
|
$
|
1,280,813
|
|
|
$
|
4,504,104
|
|
|
|
Year ended December 31, 2016
|
||||||||||||||
|
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
||||||||
Thousands of dollars except per unit amounts
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
||||||||
Oil, NGL and natural gas sales
|
|
$
|
105,450
|
|
|
$
|
127,282
|
|
|
$
|
129,259
|
|
|
$
|
142,263
|
|
Gain (loss) on derivative instruments, net
|
|
37,923
|
|
|
(92,210
|
)
|
|
—
|
|
|
1,196
|
|
||||
Other revenue, net
|
|
4,593
|
|
|
4,362
|
|
|
4,310
|
|
|
4,577
|
|
||||
Total revenue
|
|
147,966
|
|
|
39,434
|
|
|
133,569
|
|
|
148,036
|
|
||||
|
|
|
|
|
|
|
|
|
||||||||
Operating loss
|
|
(45,487
|
)
|
|
(145,028
|
)
|
|
(333,968
|
)
|
|
(52,324
|
)
|
||||
|
|
|
|
|
|
|
|
|
||||||||
Net loss (a)
|
|
(104,006
|
)
|
|
(261,550
|
)
|
|
(364,823
|
)
|
|
(85,754
|
)
|
||||
|
|
|
|
|
|
|
|
|
||||||||
Net loss attributable to the partnership
|
|
$
|
(103,786
|
)
|
|
$
|
(261,315
|
)
|
|
$
|
(364,600
|
)
|
|
$
|
(85,250
|
)
|
|
|
|
|
|
|
|
|
|
||||||||
Basic net loss per common unit (b)
|
|
$
|
(0.54
|
)
|
|
$
|
(1.25
|
)
|
|
$
|
(1.71
|
)
|
|
$
|
(0.40
|
)
|
Diluted net loss per common unit (b)
|
|
$
|
(0.54
|
)
|
|
$
|
(1.25
|
)
|
|
$
|
(1.71
|
)
|
|
$
|
(0.40
|
)
|
|
|
Year ended December 31, 2015
|
||||||||||||||
|
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
||||||||
Thousands of dollars except per unit amounts
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
||||||||
Oil, NGL and natural gas sales
|
|
$
|
162,623
|
|
|
$
|
189,636
|
|
|
$
|
153,325
|
|
|
$
|
139,688
|
|
(Loss) gain on derivative instruments, net
|
|
137,192
|
|
|
(93,432
|
)
|
|
253,012
|
|
|
141,842
|
|
||||
Other revenue, net
|
|
6,469
|
|
|
6,504
|
|
|
5,922
|
|
|
5,934
|
|
||||
Total revenue
|
|
306,284
|
|
|
102,708
|
|
|
412,259
|
|
|
287,464
|
|
||||
|
|
|
|
|
|
|
|
|
||||||||
Operating income (loss)
|
|
(17,826
|
)
|
|
(243,280
|
)
|
|
(1,276,046
|
)
|
|
(839,430
|
)
|
||||
|
|
|
|
|
|
|
|
|
||||||||
Net (loss) income (a)
|
|
(58,918
|
)
|
|
(305,581
|
)
|
|
(1,327,838
|
)
|
|
(890,676
|
)
|
||||
|
|
|
|
|
|
|
|
|
||||||||
Net (loss) income attributable to the partnership
|
|
$
|
(58,825
|
)
|
|
$
|
(305,707
|
)
|
|
$
|
(1,327,929
|
)
|
|
$
|
(890,878
|
)
|
|
|
|
|
|
|
|
|
|
||||||||
Basic net (loss) income per common unit (b)
|
|
$
|
(0.29
|
)
|
|
$
|
(1.46
|
)
|
|
$
|
(6.17
|
)
|
|
$
|
(4.25
|
)
|
Diluted net (loss) income per common unit (b)
|
|
$
|
(0.29
|
)
|
|
$
|
(1.46
|
)
|
|
$
|
(6.17
|
)
|
|
$
|
(4.25
|
)
|
NUMBER
|
|
DOCUMENT
|
2.1
|
|
Agreement and Plan of Merger, dated as of July 23, 2014, by and among Breitburn Energy Partners LP, Breitburn GP LLC, Boom Merger Sub, LLC, QR Energy LP and QRE GP, LLC (incorporated herein by reference to Exhibit 2.1 to the Current Report on Form 8-K filed by QR Energy, LP on July 29, 2014).
|
3.1
|
|
Certificate of Limited Partnership of Breitburn Energy Partners LP (incorporated herein by reference to Exhibit 3.1 to Amendment No. 1 to Form S-1 (File No. 333-134049) filed on July 13, 2006).
|
3.2
|
|
Certificate of Amendment to Certificate of Limited Partnership of Breitburn Energy Partners LP
(incorporated by reference to Exhibit 3.2 to the Quarterly Report on Form 10-Q
filed on May 5, 2015.
|
3.3
|
|
Third Amended and Restated Agreement of Limited Partnership of Breitburn Energy Partners LP
(incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on April 14, 2015).
|
3.4*
|
|
First Amendment to Third Amended and Restated Limited Partnership Agreement of Breitburn Energy Partners LP, effective as of May 13, 2016.
|
3.5
|
|
Fourth Amended and Restated Limited Liability Company Agreement of Breitburn GP LLC dated as of April 5, 2010 (incorporated herein by reference to Exhibit 3.2 to the Current Report on Form 8-K filed on April 9, 2011).
|
3.6
|
|
Amendment No. 1 to the Fourth Amended and Restated Limited Liability Company Agreement of Breitburn GP LLC dated as of December 30, 2010 (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on January 6, 2011).
|
3.7
|
|
Amendment No. 2 to the Fourth Amended and Restated Limited Liability Company Agreement of Breitburn GP LLC (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on July 2, 2014).
|
3.8*
|
|
Amendment No. 3 to the Fourth Amended and Restated Limited Liability Company Agreement of Breitburn GP LLC, effective as of May 13, 2016.
|
4.1
|
|
Indenture, dated as of October 6, 2010, by and among Breitburn Energy Partners LP, Breitburn Finance Corporation, the Guarantors named therein and U.S. Bank National Association (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on October 7, 2010).
|
4.2
|
|
Indenture, dated as of January 13, 2012, by and among Breitburn Energy Partners LP, Breitburn Finance Corporation, the Guarantors named therein and U.S. Bank National Association (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on January 13, 2012).
|
4.3
|
|
Indenture, dated as of April 8, 2015, by and among Breitburn Energy Partners LP, Breitburn Operating
LP, Breitburn Finance Corporation, the Guarantors named therein and U.S. Bank National Association
(incorporated herein by reference to Exhibit 10.4 to the Current Report on Form 8-K filed on April 14, 2015).
|
4.4
|
|
First Supplemental Indenture, dated as of August 8, 2013, by and among Breitburn Energy Partners LP, Breitburn Finance Corporation, the Guarantors named therein and U.S. Bank National Association, to the Indenture, dated as of October 6, 2010 (incorporated herein by reference to Exhibit 4.3 to the Current Report on Form 8-K filed on November 22, 2013).
|
4.5
|
|
First Supplemental Indenture, dated as of August 8, 2013, by and among Breitburn Energy Partners LP, Breitburn Finance Corporation, the Guarantors named therein and U.S. Bank National Association, to the Indenture dated as of January 13, 2012 (incorporated herein by reference to Exhibit 4.2 to the Current Report on Form 8-K filed on November 22, 2013).
|
4.6
|
|
Second Supplemental Indenture, dated as of November 24, 2014, by and among Breitburn Energy Partners LP, Breitburn Finance Corporation, the Guarantors named therein and U.S. Bank National Association, to the Indenture, dated as of October 6, 2010 (incorporated herein by reference to Exhibit 4.8 to Post-Effective Amendment No. 2 to Form S-3 (File No. 001-181531) filed on November 24, 2014).
|
4.7
|
|
Second Supplemental Indenture, dated as of November 24, 2014, by and among Breitburn Energy Partners LP, Breitburn Finance Corporation, the Guarantors named therein and U.S. Bank National Association, to the Indenture dated as of January 13, 2012 (incorporated herein by reference to Post-Effective Amendment No. 2 to Form S-3 (File No. 001-181531) filed on November 24, 2014).
|
4.8
|
|
Registration Rights Agreement, dated July 23, 2014, by and among Breitburn Energy Partners LP, QR Holdings (QRE), LLC, QR Energy Holdings, LLC, Quantum Resources B, LP, Quantum Resources A1, LP, Quantum Resources C, LP, QAB Carried WI, LP, QAC Carried WI, LP and Black Diamond Resources, LLC (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K filed by QR Energy, LP on July 29, 2014).
|
4.9
|
|
Registration Rights Agreement, dated April 8, 2015, by and among Breitburn Energy Partners LP and the purchasers listed on Schedule A thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on April 14, 2015).
|
10.1
|
|
Third Amended and Restated Credit Agreement, dated November 19, 2014, by and among Breitburn Operating LP, as borrower, Breitburn Energy Partners LP, as parent guarantor, and Wells Fargo Bank National Association as administrative agent (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on November 29, 2014).
|
10.2
|
|
First Amendment to Third Amended and Restated Credit Agreement, dated as of April 8. 2015, by and
among Breitburn Operating LP, as borrower, Breitburn Energy Partners LP, as parent guarantor, Breitburn
GP LLC, Breitburn Operating GP LLC, the subsidiary guarantors named therein, each lender signatory
thereto and Wells Fargo Bank, National Association (incorporated herein by reference to Exhibit 10.7 to
the Current Report on Form 8-K filed on April 14, 2015).
|
10.3
|
|
Consent to Third Amended and Restated Credit Agreement, dated effective as of March 28, 2016, by and among Breitburn Operating LP, Breitburn Energy Partners LP, Breitburn GP LLC, Breitburn Operating GP LLC, the guarantors named therein, the lenders signatory thereto and Wells Fargo Bank, National Association, as administrative agent for the Lenders (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on April 1, 2016).
|
10.4
|
|
Debtor-in-Possession Credit Agreement, dated as of May 19, 2016 (among Breitburn Operating LP, as borrower, Breitburn Energy Partners LP, as parent guarantor, the financial institutions from time to time party thereto and Wells Fargo Bank, National Association, as administrative agent, swing line lender and issuing lender (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on May 26, 2016).
|
10.5
|
|
First Amendment to Debtor-in-Possession Credit Agreement, dated effective as of December 15, 2016, among Breitburn Operating LP, as borrower, Breitburn Energy Partners LP, as parent guarantor, the financial institutions from time to time party thereto and Wells Fargo Bank, National Association, as administrative agent, swing line lender and issuing lender (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on December 16, 2016).
|
10.6
|
|
Second Amendment to Debtor-in-Possession Credit Agreement, dated effective as of December 15, 2016, among Breitburn Operating LP, as borrower, Breitburn Energy Partners LP, as parent guarantor, the financial institutions from time to time party thereto and Wells Fargo Bank, National Association, as administrative agent, swing line lender and issuing lender (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on December 16, 2016).
|
10.7
|
|
Amended and Restated Series B Preferred Unit Purchase Agreement, dated as of April 8, 2015, by and
among Breitburn Energy Partners LP, EIG Redwood Equity Aggregator, LP, ACMO BBEP Corp. and the
other purchasers listed on Schedule A thereto (incorporated herein by reference to Exhibit 10.1 to the
Current Report on Form 8-K filed on April 14, 2015).
|
10.8
|
|
Board Representation and Standstill Agreement, dated as of April 8, 2015, by and among Breitburn GP
LLC, Breitburn Energy Partners LP and EIG Redwood Equity Aggregator, LP (incorporated herein by
reference to Exhibit 10.2 to the Current Report on Form 8-K filed on April 14, 2015).
|
10.9
|
|
Amended and Restated Purchase Agreement, dated as of April 8, 2015, by and among Breitburn Energy
Partners LP, Breitburn Operating LP, Breitburn Finance Corporation, the guarantors party thereto and the
purchasers listed on Schedule I thereto (incorporated herein by reference to Exhibit 10.3 to the Current
Report on Form 8-K filed on April 14, 2015).
|
10.10
|
|
Security Agreement, dated as of April 8, 2015, by and among Breitburn Operating LP, Breitburn Energy
Partners LP, Breitburn Finance Corporation, each of the subsidiary entities named therein and U.S. Bank
National Association (incorporated herein by reference to Exhibit 10.5 to the Current Report on Form 8-
K filed on April 14, 2015).
|
10.11
|
|
Intercreditor Agreement, dated as of April 8, 2015, by and among Wells Fargo Bank, National Association,
U.S. Bank National Association, Breitburn Energy Partners LP, Breitburn Finance Corporation, Breitburn
Operating LP and each of the subsidiary entities named therein (incorporated herein by reference to Exhibit
10.6 to the Current Report on Form 8-K filed on April 14, 2015).
|
10.12
|
|
Third Amended and Restated Administrative Services Agreement, dated May 8, 2012, by and between Pacific Coast Energy Company L.P. and Breitburn Management Company LLC (incorporated herein by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2012 filed on August 8, 2012).
|
10.13
|
|
Amendment No. 1 to the Third Amended and Restated Administrative Services Agreement between Pacific Coast Energy Company LP and Breitburn Management Company LLC dated March 18, 2014 (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on March 20, 2014).
|
10.14
|
|
Amendment No. 2 to the Third Amended and Restated Administrative Services Agreement between Pacific Coast Energy Company LP and Breitburn Management Company LLC dated June 30, 2014 (incorporated herein by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2014 filed on November 5, 2014).
|
10.15
|
|
Amendment No. 3 to the Third Amended and Restated Administrative Services Agreement between Pacific Coast Energy Company LP and Breitburn Management Company LLC dated July 31, 2014 (incorporated herein by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2014 filed on November 5, 2014).
|
10.16
|
|
Amendment No. 4 to the Third Amended and Restated Administrative Services Agreement between Pacific Coast Energy Company LP and Breitburn Management Company LLC dated August 29, 2014 (incorporated herein by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2014 filed on November 5, 2014).
|
10.17
|
|
Amendment No. 5 to the Third Amended and Restated Administrative Services Agreement between Pacific Coast Energy Company LP and Breitburn Management Company LLC dated May 1, 2015 (incorporated hereby by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2015 filed on May 5, 2015.
|
10.18
|
|
Amendment No. 6 to the Third Amended and Restated Administrative Services Agreement between Pacific Coast Energy Company LP and Breitburn Management Company LLC dated December 22, 2015 (incorporated herein by reference to Exhibit 10.14 to the Annual Report on Form 10-K for the year ended December 31, 2015 filed on February 26, 2016).
|
10.19
|
|
Amendment No. 7 to the Third Amended and Restated Administrative Services Agreement between Pacific Coast Energy Company LP and Breitburn Management Company LLC dated January 29, 2016 (incorporated herein by reference to Exhibit 10.15 to the Annual Report on Form 10-K for the year ended December 31, 2015 filed on February 26, 2016).
|
10.20
|
|
Omnibus Agreement, dated August 26, 2008, by and among Breitburn Energy Holdings LLC, BEC (GP) LLC, Breitburn Energy Company LP, Breitburn GP LLC, Breitburn Management Company LLC and Breitburn Energy Partners LP (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on September 2, 2008).
|
10.21
|
|
First Amendment to Omnibus Agreement, dated May 8, 2012, by and among Breitburn Energy Partners LP, Breitburn GP LLC, Breitburn Management Company LLC, Pacific Coast Energy Company L.P., Pacific Coast Energy Holdings LLC and PCEC (GP) LLC (incorporated herein by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2012 filed on August 8, 2012).
|
10.22
|
|
Amendment No. 1 to the Operations and Proceeds Agreement, relating to the Dominguez Field and dated October 10, 2006 entered into on June 17, 2008 by and between BreitBurn Energy Company L.P. and Breitburn Operating LP (incorporated herein by reference to Exhibit 10.6 to the Current Report on Form 8-K filed on June 23, 2008).
|
10.23
|
|
Amendment No. 1 to the Surface Operating Agreement dated October 10, 2006 entered into on June 17, 2008 by and between BreitBurn Energy Company L.P. and its predecessor BreitBurn Energy Corporation and Breitburn Operating LP (incorporated herein by reference to Exhibit 10.7 to the Current Report on Form 8-K (File No. 001-33055) filed on June 23, 2008).
|
10.24
|
|
Indemnity Agreement between Breitburn Energy Partners LP, Breitburn GP LLC and Halbert S. Washburn, together with a schedule identifying other substantially identical agreements between Breitburn Energy Partners LP, Breitburn GP LLC and each of its executive officers and non-employee directors identified on the schedule (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on November 4, 2009).
|
10.25
|
|
Third Amended and Restated Employment Agreement dated December 30, 2010 among Breitburn Management Company LLC, Breitburn GP LLC, Breitburn Energy Partners LP and Halbert S. Washburn (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on January 6, 2011).
|
10.26
|
|
Amended and Restated Employment Agreement dated December 30, 2010 among Breitburn Management Company LLC, Breitburn GP LLC, Breitburn Energy Partners LP and Mark L. Pease (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K filed on January 6, 2011).
|
10.27
|
|
Second Amended and Restated Employment Agreement dated December 30, 2010 among Breitburn Management Company LLC, Breitburn GP LLC, Breitburn Energy Partners LP and James G. Jackson (incorporated herein by reference to Exhibit 10.4 to the Current Report on Form 8-K filed on January 6, 2011).
|
10.28
|
|
Amended and Restated Employment Agreement dated December 30, 2010 among Breitburn Management Company LLC, Breitburn GP LLC, Breitburn Energy Partners LP and Gregory C. Brown (incorporated herein by reference to Exhibit 10.5 to the Current Report on Form 8-K filed on January 6, 2011).
|
10.29†
|
|
Retirement Agreement, dated as of November 30, 2012, among Breitburn Energy Partners LP, Breitburn GP LLC and Randall H. Breitenbach (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on December 6, 2012).
|
10.30†
|
|
First Amended and Restated Breitburn Energy Partners LP 2006 Long-Term Incentive Plan effective as of October 29, 2009 (incorporated herein by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2009 filed on November 6, 2009).
|
10.31†
|
|
First Amendment to the First Amended and Restated Breitburn Energy Partners LP 2006 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.2 to the Form S-8 Registration Statement (File No. 333-181526) filed on May 18, 2012).
|
10.32†
|
|
Second Amendment to First Amended and Restated BreitBurn Energy Partners L.P. 2006 Long-Term
Incentive Plan effective as of June 18, 2015 (incorporated herein by reference to Exhibit 10.1 to the
Current Report on Form 8-K filed on June 18, 2015).
|
10.33†
|
|
Omnibus First Amendment to the Breitburn Energy Partners LP 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreements, dated as of November 30, 2012, among Breitburn Energy Partners LP, Breitburn GP LLC and Randall H. Breitenbach (incorporated herein by reference to Exhibit 10.2 to the Current Report on form 8-K filed on December 6, 2012).
|
10.34†
|
|
Form of Breitburn Energy Partners LP 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Deferred Payment Award) for 2013 grants (incorporated herein by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2013 filed on May 3, 2013).
|
10.35†
|
|
Form of Breitburn Energy Partners LP 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Employment Agreement Form) for 2015 grants (incorporated herein by reference to Exhibit 10.49 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2014 filed on March 2, 2015).
|
10.36†
|
|
Form of Breitburn Energy Partners LP 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Non-Employment Agreement Form) for 2015 grants (incorporated herein by reference to Exhibit 10.50 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2014 filed on March 2, 2015).
|
10.37†
|
|
Form of Breitburn Energy Partners LP 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Director Form) for 2015 grants (incorporated herein by reference to Exhibit 10.51 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2014 filed on March 2, 2015).
|
10.38†
|
|
Form of Breitburn Energy Partners LP 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Stock-Settled) (Employment Agreement Form) for 2016 grants (incorporated herein by reference to Exhibit 10.39 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2015 filed on February 26, 2016).
|
10.39†
|
|
Form of Breitburn Energy Partners LP 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Stock-Settled) (Non-Employment Agreement Form) for 2016 grants (incorporated herein by reference to Exhibit 10.40 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2015 filed on February 26, 2016).
|
10.40†
|
|
Form of Breitburn Energy Partners LP 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Stock-Settled) (Director Form) for 2016 grants (incorporated herein by reference to Exhibit 10.41 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2015 filed on February 26, 2016).
|
10.41†
|
|
Form of Breitburn Energy Partners LP 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Cash-Settled) (Employment Agreement Form) for 2016 grants (incorporated herein by reference to Exhibit 10.42 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2015 filed on February 26, 2016).
|
10.42†
|
|
Form of Breitburn Energy Partners LP 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Cash-Settled) (Non-Employment Agreement Form) for 2016 grants (incorporated herein by reference to Exhibit 10.43 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2015 filed on February 26, 2016).
|
10.43†
|
|
Form of Breitburn Energy Partners LP 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Cash-Settled) (Director Form) for 2016 grants (incorporated herein by reference to Exhibit 10.44 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2015 filed on February 26, 2016).
|
GENERAL PARTNER:
|
|
|
|
|
|
BREITBURN GP LLC
|
|
|
|
By:
|
/s/ James G. Jackson
|
|
James G. Jackson
|
|
Chief Financial Officer
|
SOLE MEMBER:
|
|
|
|
BREITBURN ENERGY PARTNERS LP
|
|
|
|
|
|
By:
|
BREITBURN GP LLC,
|
|
its general partner
|
|
|
By:
|
/s/ James G. Jackson
|
|
James G. Jackson
|
|
Chief Financial Officer
|
|
|
Year Ended December 31,
|
||||||||||||||||||
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Earnings Available for Fixed Charges
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net (loss) income attributable to the partnership
|
|
$
|
(814,339
|
)
|
|
$
|
(2,583,339
|
)
|
|
$
|
421,333
|
|
|
$
|
(43,671
|
)
|
|
$
|
(40,801
|
)
|
Add: income tax (benefit) expense
|
|
(1,835
|
)
|
|
1,527
|
|
|
(73
|
)
|
|
905
|
|
|
84
|
|
|||||
Less: income from equity investments
|
|
538
|
|
|
679
|
|
|
(31
|
)
|
|
521
|
|
|
692
|
|
|||||
Pre-tax (loss) income before non-controlling interests and income from equity investees
|
|
(816,712
|
)
|
|
(2,582,491
|
)
|
|
421,291
|
|
|
(43,287
|
)
|
|
(41,409
|
)
|
|||||
Add:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed charges
|
|
156,661
|
|
|
213,106
|
|
|
130,275
|
|
|
88,766
|
|
|
67,990
|
|
|||||
Amortization of capitalized interest
|
|
183
|
|
|
274
|
|
|
69
|
|
|
52
|
|
|
27
|
|
|||||
Distributed income of equity investments
|
|
—
|
|
|
(576
|
)
|
|
209
|
|
|
466
|
|
|
1,179
|
|
|||||
Less:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Capitalized interest
|
|
149
|
|
|
155
|
|
|
326
|
|
|
128
|
|
|
54
|
|
|||||
Preferred unit distributions
|
|
5,500
|
|
|
16,500
|
|
|
9,350
|
|
|
—
|
|
|
—
|
|
|||||
Total earnings available for fixed charges
|
|
$
|
(665,517
|
)
|
|
$
|
(2,386,342
|
)
|
|
$
|
542,168
|
|
|
$
|
45,869
|
|
|
$
|
27,733
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed Charges
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest and other financing costs (a)
|
|
$
|
154,509
|
|
|
$
|
208,933
|
|
|
$
|
128,305
|
|
|
$
|
87,195
|
|
|
$
|
66,729
|
|
Estimated interest within rental expense
|
|
2,152
|
|
|
4,173
|
|
|
1,970
|
|
|
1,571
|
|
|
1,261
|
|
|||||
Total fixed charges
|
|
$
|
156,661
|
|
|
$
|
213,106
|
|
|
$
|
130,275
|
|
|
$
|
88,766
|
|
|
$
|
67,990
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Preferred Unit Distributions
|
|
5,500
|
|
|
16,500
|
|
|
9,350
|
|
|
—
|
|
|
—
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total Fixed Charges and Preferred Unit Distributions
|
|
$
|
162,161
|
|
|
$
|
229,606
|
|
|
$
|
139,625
|
|
|
$
|
88,766
|
|
|
$
|
67,990
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Ratio of Earnings to Fixed Charges
|
|
—
|
|
|
—
|
|
|
4.2
|
x
|
|
—
|
|
|
—
|
|
|||||
Insufficient Coverage
|
|
$
|
(822,178
|
)
|
|
$
|
(2,599,448
|
)
|
|
$
|
—
|
|
|
$
|
(42,897
|
)
|
|
$
|
(40,257
|
)
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Ratio of Earnings to Fixed Charges and Preferred Unit Distribution
|
|
—
|
|
|
—
|
|
|
3.9
|
x
|
|
—
|
|
|
—
|
|
|||||
Insufficient Coverage
|
|
$
|
(827,678
|
)
|
|
$
|
(2,615,948
|
)
|
|
$
|
—
|
|
|
$
|
(42,897
|
)
|
|
$
|
(40,257
|
)
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
(a) Includes capitalized interest and settlements paid on interest rate swaps.
|
SUBSIDIARIES OF BREITBURN ENERGY PARTNERS LP
|
||
|
|
|
Name
|
|
Jurisdiction
|
Breitburn Operating GP LLC
|
|
Delaware
|
Breitburn Operating LP
|
|
Delaware
|
Alamitos Company
|
|
California
|
Breitburn Florida LLC
|
|
Delaware
|
Breitburn Sawtelle LLC
|
|
Delaware
|
GTG Pipeline LLC
|
|
Virginia
|
Mercury Michigan Company, LLC
|
|
Michigan
|
Phoenix Production Company
|
|
Wyoming
|
Breitburn Transpetco LP LLC
|
|
Delaware
|
Breitburn Transpetco GP LLC
|
|
Delaware
|
Transpetco Pipeline Company, L.P.
|
|
Delaware
|
Breitburn Oklahoma LLC
|
|
Delaware
|
Terra Energy Company LLC
|
|
Michigan
|
Terra Pipeline Company LLC
|
|
Michigan
|
Beaver Creek Pipeline, L.L.C.
|
|
Michigan
|
Breitburn GP LLC
|
|
Delaware
|
Breitburn Management Company LLC
|
|
Delaware
|
Breitburn Finance Corporation
|
|
Delaware
|
Breitburn Collingwood Utica LLC
|
|
Delaware
|
QR Energy, LP
|
|
Delaware
|
QRE GP, LLC
|
|
Delaware
|
QRE Operating, LLC
|
|
Delaware
|
13640 BRIARWICK DRIVE, SUITE 100
AUSTIN, TEXAS 78729-1707
512-249-7000
|
306 WEST SEVENTH STREET, SUITE 302
FORT WORTH, TEXAS 76102-4905
817- 336-2461
|
1000 LOUISIANA STREET, SUITE 1900
HOUSTON, TEXAS 77002-5017
713-651-9944
|
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
|
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.
|
|
|
/s/ Halbert S. Washburn
|
|
|
|
Halbert S. Washburn
|
|
|
|
Chief Executive Officer of Breitburn GP LLC
|
|
|
|
|
|
Dated:
|
March 8, 2017
|
|
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
|
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.
|
|
|
/s/ James G. Jackson
|
|
|
|
James G. Jackson
|
|
|
|
Chief Financial Officer of Breitburn GP LLC
|
|
|
|
|
|
Dated:
|
March 8, 2017
|
|
(1)
|
the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
|
(2)
|
the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.
|
|
|
/s/ Halbert S. Washburn
|
|
|
Halbert S. Washburn
|
|
|
Chief Executive Officer of Breitburn GP LLC
|
|
|
|
Dated:
|
March 8, 2017
|
|
(1)
|
the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
|
(2)
|
the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.
|
|
|
/s/ James G. Jackson
|
|
|
James G. Jackson
|
|
|
Chief Executive Officer of Breitburn GP LLC
|
|
|
|
Dated:
|
March 8, 2017
|
|
|
|
Net Reserves
|
|
Future Net Revenue (M$)
|
||||||
|
|
Oil
|
|
NGL
|
|
Gas
|
|
|
|
Present Worth
|
Category
|
|
(MBBL)
|
|
(MBBL)
|
|
(MMCF)
|
|
Total
|
|
at 10%
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Producing
|
|
56,359.6
|
|
8,727.8
|
|
399,511.3
|
|
596,420.7
|
|
522,548.8
|
Proved Developed Non-Producing
|
|
7,914.6
|
|
1,008.2
|
|
14,023.8
|
|
144,367.3
|
|
59,234.0
|
Proved Undeveloped
|
|
23,527.4
|
|
4,287.2
|
|
24,875.1
|
|
337,255.4
|
|
93,680.9
|
|
|
|
|
|
|
|
|
|
|
|
Total Proved
|
|
87,801.7
|
|
14,023.2
|
|
438,410.2
|
|
1,078,043.9
|
|
675,463.8
|
|
|
Sincerely,
|
|
|
|
|
|
|
|
NETHERLAND, SEWELL & ASSOCIATES, INC.
|
|
|
|
Texas Registered Engineering Firm F-2699
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ C.H. (Scott) Rees III
|
|
|
By:
|
|
|
|
|
C.H. (Scott) Rees III, P.E.
|
|
|
|
Chairman and Chief Executive Officer
|
|
|
|
|
|
|
|
|
|
/s/ C. Ashley Smith
|
|
/s/ Mike K. Norton
|
By:
|
|
By:
|
|
|
C. Ashley Smith, P.E. 100560
|
|
Mike K. Norton, P.G. 441
|
|
Vice President
|
|
Senior Vice President
|
|
|
|
|
|
|
|
|
Date Signed: February 17, 2017
|
Date Signed: February 17, 2017
|
(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
|
(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 maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:
|
(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
|
(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 date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
|
(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.
|
(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 techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
|
(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 maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:
|
(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 date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
|
(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.
|
(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 techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
|
13640 BRIARWICK DRIVE, SUITE 100
AUSTIN, TEXAS 78729-1707
512-249-7000
|
306 WEST SEVENTH STREET, SUITE 302
FORT WORTH, TEXAS 76102-4905
817- 336-2461
|
1000 LOUISIANA STREET, SUITE 1900
HOUSTON, TEXAS 77002-5017
713-651-9944
|
|
|
Proved Developed Producing
|
Proved Undeveloped
|
Total Proved
|
Net Reserves
|
|
|
|
|
Oil
|
- Mbbl
|
7,569.5
|
17,312.9
|
24,882.3
|
Gas
|
- MMcf
|
963.0
|
2,789.2
|
3,752.2
|
NGL
|
- Mbbl
|
1,265.5
|
3,593.9
|
4,859.4
|
Revenue
|
|
|
|
|
Oil
|
- M$
|
300,649.3
|
688,410.2
|
989,059.4
|
Gas
|
- M$
|
1,791.8
|
5,190.0
|
6,981.8
|
NGL
|
- M$
|
28,024.5
|
79,584.3
|
107,608.8
|
Other
|
- M$
|
39,368.1
|
62,891.5
|
102,259.7
|
Severance Taxes
|
- M$
|
1,358.2
|
2,169.8
|
3,528.0
|
Ad Valorem Taxes
|
- M$
|
23,636.6
|
54,879.1
|
78,515.8
|
Operating Expenses
|
- M$
|
140,657.5
|
102,236.3
|
242,893.8
|
3rd Party COPAS
|
- M$
|
4,619.1
|
3,275.4
|
7,894.5
|
Other Deductions
|
- M$
|
66,959.0
|
89,952.6
|
156,911.6
|
Investments
|
- M$
|
33,425.0
|
282,317.3
|
315,742.3
|
Net Operating Income
(BFIT)
|
- M$
|
99,178.3
|
301,245.4
|
400,423.8
|
Discounted at 10%
|
- M$
|
76,505.3
|
51,690.0
|
128,195.3
|
|