|
x
|
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|
¨
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|
Delaware
|
84-1060803
|
(State or other jurisdiction of
|
(I.R.S. Employer
|
incorporation or organization)
|
Identification No.)
|
800 Gessner Road, Suite 875
|
|
Houston, Texas
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77024
|
(Address of principal executive offices)
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(Zip Code)
|
Large accelerated filer
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¨
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Accelerated filer
|
¨
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Non-accelerated filer
|
¨
(Do not check if a smaller reporting company)
|
Smaller reporting company
|
x
|
|
|
PAGE
|
PART I
|
|
|
|
Item 1. BUSINESS
|
1
|
Item 1A. RISK FACTORS
|
15
|
Item 1B. UNRESOLVED STAFF COMMENTS
|
22
|
Item 2. PROPERTIES
|
23
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Item 3. LEGAL PROCEEDINGS
|
26
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Item 4. MINE SAFETY DISCLOSURES
|
27
|
|
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PART II
|
|
|
|
Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
|
27
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Item 6. SELECTED FINANCIAL DATA
|
28
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Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
28
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Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
|
43
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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
|
43
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Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
|
43
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Item 9A. CONTROLS AND PROCEDURES
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43
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Item 9B. OTHER INFORMATION
|
44
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|
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PART III
|
|
|
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Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
|
44
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Item 11. EXECUTIVE COMPENSATION
|
44
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Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
|
44
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Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
|
44
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Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
|
44
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PART IV
|
|
|
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Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
|
45
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|
1 | ||
|
2 | ||
|
|
|
Natural
|
|
|
|
|
|
|
|
|
|
Gas
|
|
Oil
|
|
NGLs
|
|
Total
|
|
|
|
(MMcf)
|
|
(MBbls)
|
|
(MBbls)
|
|
(MMcfe)
(1)
|
|
Proved Developed
|
|
135,189
|
|
496
|
|
4,882
|
|
167,457
|
|
Proved Undeveloped
|
|
424,543
|
|
1,256
|
|
17,321
|
|
536,005
|
|
Total Proved
|
|
559,732
|
|
1,752
|
|
22,203
|
|
703,462
|
|
(1) |
MMcfe is computed converting to gas using a ratio of 6 Mcf to 1 barrel of oil or NGL.
|
3 | ||
|
|
|
Natural
|
|
|
|
|
|
|
|
|
|
Gas
|
|
Oil
|
|
NGLs
|
|
Total
|
|
|
|
(MMcf)
|
|
(MBbl)
|
|
(MBbLs)
|
|
(MMcfe)
(1)
|
|
Company:
|
|
|
|
|
|
|
|
|
|
Proved Developed
|
|
662
|
|
236
|
|
|
|
2,078
|
|
Proved Undeveloped
|
|
|
|
|
|
|
|
|
|
Total Proved Reserves - Company
|
|
662
|
|
236
|
|
|
|
2,078
|
|
Company Share of Piceance Energy:
|
|
|
|
|
|
|
|
|
|
Proved Developed
|
|
45,072
|
|
165
|
|
1,627
|
|
55,829
|
|
Proved Undeveloped
|
|
141,525
|
|
419
|
|
5,774
|
|
178,680
|
|
Total Proved Reserves- Piceance Energy
|
|
186,597
|
|
584
|
|
7,401
|
|
234,509
|
|
Total Combined Proved Reserves
|
|
187,259
|
|
820
|
|
7,401
|
|
236,587
|
|
|
|
Proved
|
|
Proved
|
|
|
|
|
|
||||||||||||
|
|
Developed
|
|
Developed
|
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Proved
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||||||||||||
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Producing
|
|
Non-producing
|
|
Undeveloped
|
|
Total
(2)
|
|
||||||||||||
|
|
(M$)
|
|
(M$)
|
|
(M$)
|
|
(M$)
|
|
||||||||||||
Company:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated pre-tax future net cash flows
|
|
$
|
|
|
4,543
|
|
$
|
|
|
|
|
$
|
|
|
|
|
$
|
|
|
4,543
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
|
|
3,537
|
|
$
|
|
|
|
|
$
|
|
|
|
|
$
|
|
|
3,537
|
|
Company Share of Piceance Energy:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated pre-tax future net cash flows
|
|
$
|
|
|
73,541
|
|
$
|
|
|
29,365
|
|
$
|
|
|
215,888
|
|
$
|
|
|
318,794
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
|
|
43,812
|
|
$
|
|
|
10,372
|
|
$
|
|
|
35,141
|
|
$
|
|
|
89,325
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated pre-tax future net cash flows
|
|
$
|
|
|
78,084
|
|
$
|
|
|
29,365
|
|
$
|
|
|
215,888
|
|
$
|
|
|
323,337
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
|
|
47,349
|
|
$
|
|
|
10,372
|
|
$
|
|
|
35,141
|
|
$
|
|
|
92,862
|
|
(1) | MMcfe is computed converting gas using a ratio of 6 Mcf to 1 barrel of oil or NGL. | |
(2) | Prices are based on the historical first of the month twelve month average posted price depending on the area. These prices are adjusted for quality, energy content, regional price differentials and transportation fees. All prices are held constant throughout the lives of the properties. The average adjusted product prices are $89.70 per barrel of oil, $32.05 per barrel of natural gas liquids and $3.74 per Mcf of natural gas. |
|
|
|
|
Company Share
|
|
|
|
|||
|
|
|
|
of Piceance
|
|
|
|
|||
|
|
Company
|
|
Energy
|
|
Total
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
PV-10
|
|
$
|
3,537
|
|
$
|
89,325
|
|
$
|
92,862
|
|
Present value of future income taxes discounted at 10% (1)
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
3,537
|
|
$
|
89,325
|
|
$
|
92,862
|
|
(1) |
There is no present value of future income taxes as we believe we have sufficient net operating loss carryforwards to offset any income. Please see Note 15 Income Taxes.
|
4 | ||
|
5 | ||
|
6 | ||
|
7 | ||
|
8 | ||
|
9 | ||
|
10 | ||
|
11 | ||
|
12 | ||
|
• | requirements for obtaining drilling permits; |
• | the method of developing new fields; |
• | the spacing and operation of wells; |
• | the prevention of waste of oil and gas resources; and |
• | the plugging and abandonment of wells. |
13 | ||
|
14 | ||
|
|
•
|
our senior management’s attention, and a significant amount of our resources, may be diverted from the management of daily operations of our other businesses to the integration of HIE;
|
|
|
|
|
•
|
we could incur significant unknown and contingent liabilities for which we have limited or no contractual remedies or insurance coverage;
|
|
|
|
|
•
|
the businesses acquired in the HIE Acquisition may not perform as well as we anticipate; and
|
|
|
|
|
•
|
unexpected costs, delays and challenges may arise in integrating HIE into our existing operations.
|
|
•
|
changes in the global economy and the level of foreign and domestic production of crude oil and refined products;
|
|
|
|
|
•
|
availability of crude oil and refined products and the infrastructure to transport crude oil and refined products;
|
|
|
|
|
•
|
local factors, including market conditions, the level of operations of other refineries in our markets, and the volume of refined products imported;
|
|
|
|
|
•
|
threatened or actual terrorist incidents, acts of war, and other global political conditions;
|
|
|
|
|
•
|
government regulations; and
|
|
|
|
|
•
|
weather conditions, hurricanes or other natural disasters.
|
15 | ||
|
16 | ||
|
• | The US EPA proposed regulations in 2009, that would require the reduction of emissions of greenhouse gases from light trucks and cars, and would establish permitting thresholds for stationary sources that emit greenhouse gases and require emissions controls for those sources. Promulgation of the final rule on April 1, 2010, has resulted in a cascade of related rulemakings by the US EPA pursuant to the Federal Clean Air Act (the “CAA”) relative to controlling greenhouse gas emissions. |
• | In December 2007, the Energy Independence and Security Act was enacted into federal law, which created a second renewable fuels standard. This standard requires the total volume of renewable transportation fuels (including ethanol and advanced biofuels) sold or introduced in the U.S. to reach 18.2 billion gallons in 2014 and to increase to 36 billion gallons by 2022. However, the US EPA has proposed to reduce the total renewable and advanced biofuel requirements to 15.2 billion in 2014. | |
• | In March 2014, the US EPA published a Final Tier 3 gasoline standard that lowers the allowable sulfur level in gasoline to 10 ppm and also lowers the allowable benzene, aromatics and olefins content of gasoline. The effective date for the new standard, January 1, 2017, gives refineries nation-wide little time to engineer, permit, and implement substantial modifications. |
17 | ||
|
18 | ||
|
19 | ||
|
20 | ||
|
|
•
|
timing and amount of capital expenditures;
|
|
|
|
|
•
|
expertise and diligence in adequately performing operations and complying with applicable agreements;
|
|
|
|
|
•
|
financial resources;
|
|
|
|
|
•
|
inclusion of other participants in drilling wells; and
|
|
|
|
|
•
|
use of technology.
|
21 | ||
|
|
•
|
we may not be able to replace production with new reserves;
|
|
|
|
|
•
|
exploration and development drilling may not result in commercially productive reserves;
|
|
|
|
|
•
|
title to properties in which we or Piceance Energy has an interest may be impaired by title defects;
|
|
|
|
|
•
|
the marketability of our natural gas products depends mostly on the availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities, which are owned by third parties;
|
|
|
|
|
•
|
we have no long-term contracts to sell natural gas and oil;
|
|
|
|
|
•
|
federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays;
|
|
|
|
|
•
|
natural gas drilling and production operations require adequate sources of water to facilitate the fracturing process and the disposal of that water when it flows back to the wellbore. If we are unable to obtain adequate water supplies and dispose of the water we use or remove at a reasonable cost and within applicable environmental rules, our ability to produce natural gas commercially and in commercial quantities would be impaired.
|
Item 1B. | UNRESOLVED STAFF COMMENTS |
22 | ||
|
Item 2. | PROPERTIES |
23 | ||
|
|
|
Successor
|
|
|
Predecessor
|
|
||||||||
|
|
|
|
|
Period from
|
|
|
Period from
|
|
|
|
|
||
|
|
Year Ended
|
|
September 1
|
|
|
January 1
|
|
Year Ended
|
|
||||
|
|
December 31,
|
|
through
|
|
|
through
|
|
December 31,
|
|
||||
|
|
2013
|
|
December 31, 2012
|
|
|
August 31, 2012
|
|
2011
|
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Company:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production volume -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production (MMcfe)
|
|
|
668
|
|
|
139
|
|
|
|
5,256
|
|
|
11,682
|
|
Production from continuing operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
69
|
|
|
22
|
|
|
|
67
|
|
|
140
|
|
Natural Gas (MMcf)
|
|
|
253
|
|
|
9
|
|
|
|
4,852
|
|
|
9,948
|
|
Total (MMcfe)
|
|
|
668
|
|
|
139
|
|
|
|
5,256
|
|
|
10,788
|
|
Net average daily production-continuing operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl)
|
|
|
189
|
|
|
177
|
|
|
|
277
|
|
|
385
|
|
Natural Gas (Mcf)
|
|
|
694
|
|
|
77
|
|
|
|
19,966
|
|
|
27,254
|
|
Average sales price:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
98.29
|
|
$
|
97.66
|
|
|
$
|
96.60
|
|
$
|
80.16
|
|
Natural Gas (per Mcf)
|
|
$
|
5.35
|
|
$
|
4.32
|
|
|
$
|
3.42
|
|
$
|
5.29
|
|
Hedge gain (loss) (per Mcfe)
|
|
$
|
|
|
$
|
|
|
|
$
|
|
|
$
|
(0.04)
|
|
Lease operating costs(per Mcfe)
|
|
$
|
8.50
|
|
$
|
11.22
|
|
|
$
|
1.72
|
|
$
|
1.27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Company Share of Piceance Energy:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production volume -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production (MMcfe)
|
|
|
4,978
|
|
|
1,711
|
|
|
|
|
|
|
|
|
Production from continuing operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
16
|
|
|
6
|
|
|
|
|
|
|
|
|
NGLs (MBbls)
|
|
|
143
|
|
|
48
|
|
|
|
|
|
|
|
|
Natural Gas (MMcf)
|
|
|
4,029
|
|
|
1,391
|
|
|
|
|
|
|
|
|
Total (MMcfe)
|
|
|
4,978
|
|
|
1,711
|
|
|
|
|
|
|
|
|
Net average daily production-continuing operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl)
|
|
|
43
|
|
|
46
|
|
|
|
|
|
|
|
|
NGLs (Bbl)
|
|
|
391
|
|
|
391
|
|
|
|
|
|
|
|
|
Natural Gas (Mcf)
|
|
|
11,038
|
|
|
11,404
|
|
|
|
|
|
|
|
|
Average sales price:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Per Bbl)
|
|
$
|
85.91
|
|
$
|
77.81
|
|
|
|
|
|
|
|
|
NGLs (Per Bbl)
|
|
$
|
30.08
|
|
$
|
36.09
|
|
|
|
|
|
|
|
|
Natural Gas (per Mcf)
|
|
$
|
3.66
|
|
$
|
3.09
|
|
|
|
|
|
|
|
|
Hedge gain (loss) (per Mcfe)
|
|
$
|
(0.05)
|
|
$
|
(0.18)
|
|
|
|
|
|
|
|
|
Lease operating costs(per Mcfe)
|
|
$
|
0.60
|
|
$
|
0.53
|
|
|
|
|
|
|
|
|
24 | ||
|
|
|
Productive Wells
|
|
|
|
|
|
|
|
||||||||||
|
|
Oil (1)
|
|
Gas (1)
|
|
Developed Acres
|
|
||||||||||||
Location
|
|
Gross (2)
|
|
Net (3)
|
|
Gross (2)
|
|
Net (3)
|
|
Gross (2)
|
|
Net (3)
|
|
||||||
Company:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
California (offshore)
|
|
|
34
|
|
|
2.10
|
|
|
|
|
|
|
|
|
2,422
|
|
|
147
|
|
Colorado
|
|
|
|
|
|
|
|
|
21
|
|
|
1.05
|
|
|
210
|
|
|
11
|
|
New Mexico(4)
|
|
|
9
|
|
|
0.11
|
|
|
1
|
|
|
0.01
|
|
|
800
|
|
|
9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
43
|
|
|
2.21
|
|
|
22
|
|
|
1.06
|
|
|
3,432
|
|
|
167
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Company’s Share of Piceance Energy
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Colorado (5)
|
|
|
|
|
|
|
|
|
525
|
|
|
102.83
|
|
|
10,319
|
|
|
3,018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
43
|
|
|
2.21
|
|
|
547
|
|
|
103.89
|
|
|
13,751
|
|
|
3,185
|
|
(1)
|
Some of the wells classified as “oil” wells also produce minor amounts of natural gas. Likewise, some of the wells classified as “gas” wells also produce minor amounts of oil.
|
(2)
|
A “gross well” or “gross acre” is a well or acre in which a working interest is held. The number of gross wells or acres is the total number of wells or acres in which a working interest is owned.
|
(3)
|
A “net well” or “net acre” is deemed to exist when the sum of fractional ownership interests in gross wells or acres equals one. The number of net wells or net acres is the sum of the fractional working interests owned in gross wells or gross acres expressed as whole numbers and fractions thereof.
|
(4)
|
Our ownership interest in New Mexico wells is an overriding royalty interest.
|
(5)
|
For our 33.34% equity interest in Piceance Energy, the net wells and net developed acres are reflected as if we owned our interest directly.
|
|
|
Undeveloped Acres (1)(2)
|
|
||||
Location
|
|
Gross
|
|
Net
|
|
||
Company
|
|
|
|
|
|
|
|
Company share of Piceance Energy (3)
|
|
|
38,858
|
|
|
10,481
|
|
(1)
|
Undeveloped acreage is considered to be those lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether such acreage contains proved reserves.
|
(2)
|
There are no material near-term lease expirations for which the carrying value at December 31, 2013 has not already been impaired in consideration of these expirations or capital budgeted to convert acreage to held by production.
|
(3)
|
For our 33.34% equity interest in Piceance Energy, the net undeveloped acres are reflected as if we owned our interest directly.
|
|
|
Successor
|
|
|
Predecessor
|
|
||||||||||||||||||||
|
|
|
|
|
|
|
|
September 1
|
|
|
January 1
|
|
|
|
|
|
|
|
||||||||
|
|
Year Ended
|
|
Through
|
|
|
Through
|
|
Year Ended
|
|
||||||||||||||||
|
|
December 31, 2013
|
|
December 31, 2012
|
|
|
August 31, 2012
|
|
December 31, 2011
|
|
||||||||||||||||
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
||||||||
Company
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory Wells (1):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
0.32
|
|
|
1
|
|
|
1
|
|
Nonproductive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
0.32
|
|
|
2
|
|
|
2
|
|
(1)
|
Does not include wells in which we had only a royalty interest.
|
25 | ||
|
|
|
Successor
|
|
|
Predecessor
|
|
||||||||||||||||||||
|
|
|
|
September 1
|
|
|
January 1
|
|
|
|
|
|
|
|
||||||||||||
|
|
Year Ended
|
|
Through
|
|
|
Through
|
|
Year Ended
|
|
||||||||||||||||
|
|
December 31, 2013
|
|
December 31, 2012
|
|
|
August 31, 2012
|
|
December 31, 2011
|
|
||||||||||||||||
Company
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
||||||||
Development Wells (1):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
3
|
|
|
0.03
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
13
|
|
|
0.65
|
|
|
8
|
|
|
0.40
|
|
|
|
|
|
|
|
|
|
41
|
|
|
1.96
|
|
Nonproductive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
16
|
|
|
0.68
|
|
|
8
|
|
|
0.40
|
|
|
|
|
|
|
|
|
|
41
|
|
|
1.96
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Wells (1):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
3
|
|
|
0.03
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
13
|
|
|
0.65
|
|
|
8
|
|
|
0.40
|
|
|
|
1
|
|
|
0.32
|
|
|
42
|
|
|
2.96
|
|
Nonproductive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Wells
|
|
|
16
|
|
|
0.68
|
|
|
8
|
|
|
0.40
|
|
|
|
1
|
|
|
0.32
|
|
|
43
|
|
|
3.96
|
|
(1)
|
Does not include exploratory wells in progress.
|
Item 3. | LEGAL PROCEEDINGS |
26 | ||
|
Item 4. | MINE SAFETY DISCLOSURES |
Item 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES |
Quarter Ended
|
|
High
|
|
Low
|
|
||
Predecessor:
|
|
|
|
|
|
|
|
March 31, 2012
|
|
$
|
0.68
|
|
$
|
0.08
|
|
June 30, 2012
|
|
|
0.61
|
|
|
0.08
|
|
July 1, 2012 through August 31, 2012
|
|
|
0.05
|
|
|
0.05
|
|
Successor:
|
|
|
|
|
|
|
|
September 1, 2012 through September 30, 2012
|
|
|
14.50
|
|
|
10.05
|
|
December 31, 2012
|
|
|
12.00
|
|
|
10.20
|
|
March 31, 2013
|
|
|
14.50
|
|
|
10.00
|
|
June 30, 2013
|
|
|
17.70
|
|
|
13.60
|
|
September 30, 2013
|
|
|
19.40
|
|
|
16.10
|
|
December 31, 2013
|
|
|
25.00
|
|
|
18.50
|
|
27 | ||
|
Item 6. | SELECTED FINANCIAL DATA |
Item 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
• | refining, distribution and marketing; |
• | natural gas and oil operations; and |
• | commodity marketing and logistics |
28 | ||
|
|
|
Successor
|
|
|
Predecessor
|
|
|||||
|
|
Year Ended
December 31, 2013 |
|
September 1
through December 31, 2012 |
|
|
January 1, 2012
through August 31, 2012 |
|
|||
Refining, distribution and marketing revenues
|
|
$
|
778,126
|
|
$
|
|
|
|
$
|
|
|
Commodity marketing and logistics
|
|
|
100,149
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
|
7,739
|
|
|
2,144
|
|
|
|
23,079
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
886,014
|
|
|
2,144
|
|
|
|
23,079
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of revenues
|
|
|
848,924
|
|
|
|
|
|
|
|
|
Operating expense, excluding depreciation, depletion, and amortization expense shown separately below
|
|
|
27,251
|
|
|
|
|
|
|
|
|
Lease operating expense
|
|
|
5,627
|
|
|
1,684
|
|
|
|
9,038
|
|
Transportation expense
|
|
|
|
|
|
|
|
|
|
6,963
|
|
Production taxes
|
|
|
49
|
|
|
4
|
|
|
|
979
|
|
Exploration expense
|
|
|
|
|
|
|
|
|
|
2
|
|
Dry hole costs and impairments
|
|
|
|
|
|
|
|
|
|
151,347
|
|
Depreciation, depletion, amortization and accretion
|
|
|
5,982
|
|
|
401
|
|
|
|
16,041
|
|
Trust litigation and settlements
|
|
|
6,206
|
|
|
|
|
|
|
|
|
General and administrative expense
|
|
|
21,494
|
|
|
4,520
|
|
|
|
9,386
|
|
Acquisition and integration costs
|
|
|
9,794
|
|
|
556
|
|
|
|
|
|
Total operating expenses
|
|
|
925,372
|
|
|
7,165
|
|
|
|
193,756
|
|
Operating loss
|
|
|
(39,313)
|
|
|
(5,021)
|
|
|
|
(170,677)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from unconsolidated affiliates
|
|
|
(2,941)
|
|
|
(1,325)
|
|
|
|
(20)
|
|
Interest expense and financing costs, net
|
|
|
(19,471)
|
|
|
(1,056)
|
|
|
|
(6,852)
|
|
Other income
|
|
|
808
|
|
|
86
|
|
|
|
516
|
|
Change in value of common stock warrants
|
|
|
(10,114)
|
|
|
(4,280)
|
|
|
|
|
|
Gain on derivative instruments, net
|
|
|
410
|
|
|
|
|
|
|
|
|
Income tax benefit
|
|
|
|
|
|
2,757
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from continuing operations
|
|
|
(70,621)
|
|
|
(8,839)
|
|
|
|
(177,033)
|
|
Reorganization items:
|
|
|
|
|
|
|
|
|
|
|
|
Professional fees and administrative costs
|
|
|
|
|
|
|
|
|
|
22,354
|
|
Changes in asset fair values due to fresh start accounting adjustments
|
|
|
|
|
|
|
|
|
|
14,765
|
|
Gain on settlement of senior debt
|
|
|
|
|
|
|
|
|
|
(166,144)
|
|
Gain on settlement of liabilities
|
|
|
|
|
|
|
|
|
|
(2,571)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(70,621)
|
|
$
|
(8,839)
|
|
|
$
|
(45,437)
|
|
29 | ||
|
30 | ||
|
31 | ||
|
|
|
Refining
Distribution and Marketing |
|
Commodity
Marketing and Logistics |
|
Other
|
|
Total
|
|
||||
March 25, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
(1)
|
|
$
|
9,680
|
|
$
|
10,773
|
|
$
|
2,216
|
|
$
|
22,669
|
|
Revolver availability
|
|
|
5,000
|
|
|
|
|
|
|
|
|
5,000
|
|
ABL Facility
|
|
|
33,134
|
|
|
18,491
|
|
|
|
|
|
51,625
|
|
Total available liquidity
|
|
$
|
47,814
|
|
$
|
29,264
|
|
$
|
2,216
|
|
$
|
79,294
|
|
|
|
Refining
Distribution and Marketing |
|
Commodity
Marketing and Logistics |
|
Other
|
|
Total
|
|
||||
December 31, 2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
(1)
|
|
$
|
4,536
|
|
$
|
24,009
|
|
$
|
9,516
|
|
$
|
38,061
|
|
Revolver availability
|
|
|
5,000
|
|
|
|
|
|
|
|
|
5,000
|
|
ABL Facility
|
|
|
28,436
|
|
|
8,420
|
|
|
|
|
|
36,856
|
|
Total available liquidity
|
|
$
|
37,972
|
|
$
|
32,429
|
|
$
|
9,516
|
|
$
|
79,917
|
|
(1) | The HIE, HIE Retail and Texadian credit agreements contain certain covenants that limit our ability to distribute cash to their parent or other subsidiaries. |
32 | ||
|
33 | ||
|
34 | ||
|
|
|
Successor
|
|
|
Predecessor
|
|
|||||
|
|
Year
Ended December 31, 2013 |
|
September 1
through December 31, 2012 |
|
|
January 1
though August 31, 2012 |
|
|||
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
|
$
|
(35,677)
|
|
$
|
(4,636)
|
|
|
$
|
(20,262)
|
|
Net cash provided by (used in) investing activities
|
|
$
|
(564,500)
|
|
$
|
(17,690)
|
|
|
$
|
72,622
|
|
Net cash provided by financing activities
|
|
$
|
632,053
|
|
$
|
23,629
|
|
|
$
|
(60,340)
|
|
35 | ||
|
36 | ||
|
37 | ||
|
38 | ||
|
|
|
Total
|
|
|
2013
|
|
$
|
22,725
|
|
2014
|
|
|
13,277
|
|
2015
|
|
|
12,362
|
|
2016
|
|
|
10,375
|
|
2017
|
|
|
9,244
|
|
Thereafter
|
|
|
25,614
|
|
|
|
|
|
|
Total minimum rental payments
|
|
$
|
93,597
|
|
39 | ||
|
2013
|
|
$
|
382
|
|
2014
|
|
|
382
|
|
2015
|
|
|
382
|
|
2016
|
|
|
382
|
|
2017
|
|
|
382
|
|
Thereafter
|
|
|
840
|
|
Total minimum lease payments
|
|
|
2,750
|
|
Less amount representing interest
|
|
|
829
|
|
|
|
|
|
|
Total minimum rental payments
|
|
$
|
1,921
|
|
40 | ||
|
41 | ||
|
42 | ||
|
Item 7A.
|
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
|
Item 8.
|
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
|
Item 9.
|
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES
|
Item 9A.
|
CONTROLS AND PROCEDURES
|
43 | ||
|
Item 9B. | OTHER INFORMATION |
Item 10. | DIRECTORS AND EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
Item 11. | EXECUTIVE COMPENSATION |
Item 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
Item 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
Item 14. | PRINCIPAL ACCOUNTING FEES AND SERVICES |
44 | ||
|
Item 15. | EXHIBITS, FINANCIAL STATEMENT SCHEDULES |
|
Page No.
|
Reports of Independent Registered Public Accounting Firms
|
F-1
|
Consolidated Balance Sheets
|
F-5
|
Consolidated Statements of Operations
|
F-6
|
Consolidated Statements of Changes in Stockholders’ Equity
|
F-7
|
Consolidated Statements of Cash Flows
|
F-8
|
Notes to Consolidated Financial Statements
|
F-9
|
2.1
|
Third Amended Joint Chapter 11 Plan of Reorganization of Delta Petroleum Corporation and Its Debtor Affiliates dated August 13, 2012. Incorporated by reference to Exhibit 2.1 to the company’s Current Report on Form 8-K filed on September 7, 2012.****
|
|
|
2.2
|
Contribution Agreement, dated as of June 4, 2012, among Piceance Energy, LLC, Laramie Energy, LLC and the company. Incorporated by reference to Exhibit 2.2 to the company’s Current Report on Form 8-K filed on June 8, 2012.****
|
|
|
2.3
|
Purchase and Sale Agreement dated as of December 31, 2012, by and among the company, SEACOR Energy Holdings Inc., SEACOR Holdings Inc., and Gateway Terminals LLC. Incorporated by reference to Exhibit 2.1 to the company’s Current Report on Form 8-K filed on January 3, 2013.****
|
|
|
2.4
|
Membership Interest Purchase Agreement dated as at June 17, 2013, by and among Tesoro Corporation, Tesoro Hawaii, LLC and Hawaii Pacific Energy, LLC. Incorporated by reference to Exhibit 2.4 to the company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2013, filed on August 14, 2013.****
|
|
|
3.1
|
Amended and Restated Certificate of Incorporation of the company. Incorporated by reference to Exhibit 3.1 to the company’s Current Report on Form 8-K filed on September 7, 2012.
|
|
|
3.2
|
Certificate of Amendment to the Certificate of Incorporation of the company dated effective September 25, 2013. Incorporated by reference to Exhibit 3.1 to the company’s Current Report on Form 8-K filed on September 27, 2014.
|
|
|
3.3
|
Certificate of Amendment to Amended and Restated Certificate of Incorporation of the company dated January 23, 2014. Incorporated by reference to Exhibit 3.1 to the company’s Current Report on Form 8-K filed on January 23, 2014.
|
|
|
3.4
|
Amended and Restated Bylaws of the company. Incorporated by reference to Exhibit 3.2 to the company’s Current Report on Form 8-K filed on September 7, 2012.
|
|
|
4.1
|
Form of the company’s Common Stock Certificate. ***
|
|
|
4.2
|
Stockholders Agreement effective as of August 31, 2012, by and among the company, Zell Credit Opportunities Master Fund, L.P., Waterstone Capital Management, L.P., Pandora Select Partners, LP, Iam Mini-Fund 14 Limited, Whitebox Multi-Strategy Partners, LP, Whitebox Credit Arbitrage Partners, LP, HFR RVA Combined Master Trust, Whitebox Concentrated Convertible Arbitrage Partners, LP and Whitebox Asymmetric Partners, LP. Incorporated by reference to Exhibit 4.2 to the company’s Current Report on Form 8-K filed on September 7, 2012.
|
|
|
4.3
|
Registration Rights Agreement effective as of August 31, 2012, by and among the company, Zell Credit Opportunities Master Fund, L.P., Waterstone Capital Management, L.P., Pandora Select Partners, LP, Iam Mini-Fund 14 Limited, Whitebox Multi-Strategy Partners, LP, Whitebox Credit Arbitrage Partners, LP, HFR RVA Combined Master Trust, Whitebox Concentrated Convertible Arbitrage Partners, LP and Whitebox Asymmetric Partners, LP. Incorporated by reference to Exhibit 4.3 to the company’s Current Report on Form 8-K filed on September 7, 2012.
|
|
|
4.4
|
Warrant Issuance Agreement dated as of August 31, 2012, by and among the company and WB Delta, Ltd., Waterstone Offshore ER Fund, Ltd., Prime Capital Master SPC, GOT WAT MAC Segregated Portfolio, Waterstone Market Neutral MAC51, Ltd., Waterstone Market Neutral Master Fund, Ltd., Waterstone MF Fund, Ltd., Nomura Waterstone Market Neutral Fund, ZCOF Par Petroleum Holdings, L.L.C. and Highbridge International, LLC. Incorporated by reference to Exhibit 4.4 to the company’s Current Report on Form 8-K filed on September 7, 2012.
|
45 | ||
|
4.5
|
Form of Common Stock Purchase Warrant dated as of June 4, 2012. Incorporated by reference to Exhibit 4.5 to the company’s Current Report on Form 8-K filed on September 7, 2012.
|
|
|
4.6
|
Par Petroleum Corporation 2012 Long Term Incentive Plan. Incorporated by reference to Exhibit 4.1 to the company’s Registration Statement on Form S-8 filed on December 21, 2012.*
|
10.1
|
Delayed Draw Term Loan Credit Agreement dated as of August 31, 2012, by and among the company, the Guarantors party thereto, the Lenders party thereto and Jefferies Finance LLC, as administrative agent for the Lenders. Incorporated by reference to Exhibit 10.1 to the company’s Current Report on Form 8-K filed on September 7, 2012.
|
|
|
10.2
|
First Amendment to Delayed Draw Term Loan Credit Agreement, Joinder, Waiver, Consent and Omnibus Amendment Agreement dated as of September 28, 2012, by and among the company, the Guarantors party thereto, the Lenders party thereto and Jefferies Finance LLC, as administrative agent for the Lenders.
Incorporated by reference to Exhibit 10.2 to the Company’s Annual Report on Form 10-K filed on March 27, 2013.
|
|
|
10.3
|
Waiver and Second Amendment to Delayed Draw Term Loan Credit Agreement, Joinder, Waiver, Consent and Omnibus Amendment Agreement dated as of November 29, 2012, by and among the company, the Guarantors party thereto, the Lenders party thereto and Jefferies Finance LLC, as administrative agent for the Lenders.
Incorporated by reference to Exhibit 10.3 to the Company’s Annual Report on Form 10-K filed on March 27, 2013.
|
|
|
10.4
|
Third Amendment to Delayed Draw Term Loan Credit Agreement, Joinder, Waiver, Consent and Omnibus Amendment Agreement dated as of December 28, 2012, by and among the company, the Guarantors party thereto, the Lenders party thereto and Jefferies Finance LLC, as administrative agent for the Lenders. Incorporated by reference to Exhibit 10.1 to the company’s Current Report on Form 8-K filed on January 3, 2013.
|
|
|
10.5
|
Fourth Amendment to Delayed Draw Term Loan Credit Agreement dated as of April 19, 2013, by and among the company, the Guarantors party thereto, the Lenders party thereto and Jefferies Finance LLC, as administrative agent for the Lenders. Incorporated by reference to Exhibit 10.1 to the company’s Current Report on Form 8-K filed on April 22, 2013.
|
|
|
10.6
|
Fifth Amendment to Delayed Draw Term Loan Credit Agreement dated as of June 4, 2013, by and among the company, the Guarantors party thereto, the lenders party thereto and Jeffries Finance LLC, as administrative agent for the Lenders. Incorporated by reference to Exhibit 10.2 to the company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2013, filed on August 14, 2013.
|
|
|
10.7
|
Sixth Amendment to Delayed Draw Term Loan Agreement dated as of June 12, 2013, by and among the company, the Guarantors party thereto, the Lenders party thereto and Jeffries Finance, LLC, as administrative agent for the Lenders, Incorporated by reference 10.2 to the company’s Current Report on Form 8-K filed on June 17, 2013.
|
|
|
10.8
|
Seventh Amendment to Delayed Draw Term Loan Agreement dated as of June 17, 2013, by and among the company, the Guarantors party thereto, the Lenders party thereto and Jeffries Finance, LLC, as administrative agent for the Lenders, Incorporated by reference 10.3 to the company’s Current Report on Form 8-K filed on June 17, 2013.
|
|
|
10.9
|
Eighth Amendment to Delayed Draw Term Loan Agreement dated as of June 14, 2013, by and among the company, the Guarantors party thereto, the Lenders party thereto and Jeffries Finance, LLC, as administrative agent for the Lenders, Incorporated by reference 10.1 to the company’s Current Report on Form 8-K filed on June 24, 2013.
|
|
|
10.10
|
Ninth Amendment to Delayed Draw Term Loan Agreement dated as of August 1, 2013, by and among the company, the Guarantors party thereto, the Lenders party thereto and Jeffries Finance, LLC, as administrative agent for the Lenders, Incorporated by reference 10.10 to the company’s Registration Statement on Form S-1 filed on November 22, 2013.
|
|
|
10.11
|
Tenth Amendment to Delayed Draw Term Loan Agreement dated as of September 25, 2013, by and among the company, the Guarantors party thereto, the Lenders party thereto and Jeffries Finance, LLC, as administrative agent for the Lenders, Incorporated by reference 10.8 to the company’s Current Report on Form 8-K filed on September 27, 2014.
|
|
|
10.12
|
Eleventh Amendment to Delayed Draw Term Loan Agreement dated as of January 23, 2014, by and among the company, the Guarantors party thereto, ZCOF Par Petroleum Holdings, L.L.C. and Jeffries Finance, LLC, as administrative agent for the Lenders, Incorporated by reference 10.1 to the company’s Current Report on Form 8-K filed on January 23, 2014.
|
|
|
10.13
|
Amended and Restated Limited Liability company Agreement for Piceance Energy, LLC. Incorporated by reference to Exhibit 10.2 to the company’s Current Report on Form 8-K filed on September 7, 2012.
|
46 | ||
|
10.14
|
Credit Agreement dated as of June 4, 2012 among Piceance Energy, LLC, the financial institutions party thereto, JPMorgan Chase Bank, N.A., as administrative agent, and Wells Fargo Bank, National Association, as syndication agent. Incorporated by reference to Exhibit 10.3 to the company’s Current Report on Form 8-K filed on September 7, 2012.
|
|
|
10.15
|
First Amendment to Credit Agreement dated August 31, 2012, by and among Piceance Energy, LLC, the financial institutions party thereto, and JPMorgan Chase Bank, N.A. Incorporated by reference to Exhibit 10.4 to the company’s Current Report on Form 8-K filed on September 7, 2012.
|
|
|
10.16
|
Wapiti Recovery Trust Agreement dated August 27, 2012, by and among the company, DPCA LLC, Delta Exploration company, Inc., Delta Pipeline, LLC, DLC, Inc., CEC, Inc., Castle Texas Production Limited Partnership, Amber Resources company of Colorado, Castle Exploration company, Inc. and John T. Young. Incorporated by reference to Exhibit 10.5 to the company’s Current Report on Form 8-K filed on September 7, 2012.
|
|
|
10.17
|
Delta Petroleum General Recovery Trust Agreement dated August 27, 2012, by and among the company, DPCA LLC, Delta Exploration company, Inc., Delta Pipeline, LLC, DLC, Inc., CEC, Inc., Castle Texas Production Limited. Partnership, Amber Resources company of Colorado, Castle Exploration company, Inc. and John T. Young. Incorporated by reference to Exhibit 10.6 to the company’s Current Report on Form 8-K filed on September 7, 2012.
|
|
|
10.18
|
Pledge Agreement dated August 31, 2012, by Par Piceance Energy Equity LLC in favor of Jefferies Finance LLC. Incorporated by reference to Exhibit 10.7 to the company’s Current Report on Form 8-K filed on September 7, 2012.
|
|
|
10.19
|
Intercreditor Agreement dated August 31, 2012, by and among JP Morgan Chase Bank, N.A., as administrative agent for the First Priority Secured Parties (as defined therein), Jefferies Finance LLC, as administrative agent for the Second Priority Secured Parties (as defined therein), the company and Par Piceance Energy Equity LLC. Incorporated by reference to Exhibit 10.8 to the company’s Current Report on Form 8-K filed on September 7, 2012.
|
|
|
10.20
|
Pledge and Security Agreement, dated August 31, 2012, by the company and certain of its subsidiaries in favor of Jefferies Finance LLC. Incorporated by reference to Exhibit 10.9 to the company’s Current Report on Form 8-K filed on September 7, 2012.
|
|
|
10.21
|
Letter of Credit Facility Agreement dated as of December 27, 2012, by and between the company and Compass Bank. Incorporated by reference to Exhibit 10.2 to the company’s Current Report on Form 8-K filed on January 3, 2013.
|
|
|
10.22
|
Form of Indemnification Agreement between the company and its Directors and Executive Officers. Incorporated by reference to Exhibit 10.1 to the company’s Current Report on Form 8-K filed on October 19, 2012.*
|
|
|
10.23
|
Uncommitted Credit Agreement dated as of June 12, 2013, by and among Texadian Energy, Inc., Texadian Energy Canada Limited and BNP Paribas. Incorporated by reference to Exhibit 10.1 to the company’s Current Report on Form 8-K filed in June 17, 2013.
|
|
|
10.24
|
Common Stock Purchase Agreement dated effective as of September 10, 2013, by and among the company and the Purchasers party thereto. Incorporated by reference to Exhibit 10.1 to the company’s Current Report on Form 8-K filed in September 13, 2013.
|
|
|
10.25
|
Letter Agreement dated as of September 17, 2013 but effective as of January 1, 2013, by and between Whitebox Advisors, LLC and the company. Incorporated by reference to Exhibit 10.18 to the company’s Quarterly Report on Form 10-Q filed on November 14, 2013.
|
|
|
10.26
|
Letter Agreement dated as of September 17, 2013 but effective as of January 1, 2013, by and between Equity Group Investments and the company. Incorporated by reference to Exhibit 10.17 to the company’s Quarterly Report on Form 10-Q filed on November 14, 2013.
|
|
|
10.27
|
Framework Agreement dated as of September 25, 2013, by and among Hawaii Pacific Energy, LLC, Tesoro Hawaii, LLC and Barclays Bank PLC. Incorporated by reference to Exhibit 10.1 to the company’s Quarterly Report on Form 80K filed on September 27, 2013.
|
|
|
10.28
|
Storage and Services Agreement dated as of September 25, 2013, by and among Tesoro Hawaii, LLC and Barclays Bank PLC. Incorporated by reference to Exhibit 10.2 to the company’s Current Report on Form 8-K filed on September 27, 2013.
|
|
|
10.29
|
Agency and Advisory Agreement dated as of September 25, 2013, by and among Tesoro Hawaii, LLC and Barclays Bank PLC. Incorporated by reference to Exhibit 10.3 to the company’s Current Report on Form 8-K filed on September 27, 2013.
|
|
|
10.30
|
Inventory First Lien Security Agreement dated as of September 25, 2013, by and among Tesoro Hawaii, LLC and Wells Fargo Bank, N.A, as inventory collateral agent. Incorporated by reference to Exhibit 10.4 to the company’s Current Report on Form 8-K filed on September 27, 2013.
|
47 | ||
|
10.31
|
First Lien Mortgage dated as of September 25, 2013, by and among Tesoro Hawaii, LLC and Wells Fargo Bank, N.A, as inventory collateral agent. Incorporated by reference to Exhibit 10.5 to the company’s Current Report on Form 8-K filed on September 27, 2013.
|
|
|
10.32
|
Intercreditor Agreement dated as of September 25, 2013, by and among Barclays Bank PLC, Wells Fargo Bank, N.A, as inventory collateral agent, Deutsche Bank AG New York Branch, as ABL loan collateral agent and as administrative agent pursuant to the ABL Credit Agreement, Hawaii Pacific Energy, LLC, and Tesoro Hawaii, LLC. Incorporated by reference to Exhibit 10.6 to the company’s Current Report on Form 8-K filed on September 27, 2013.
|
|
|
10.33
|
Membership Interests First Lien Pledge Agreement dated as of September 25, 2013, by and between Hawaii Pacific Energy, LLC and Wells Fargo Bank, N.A, as inventory collateral agent. Incorporated by reference to Exhibit 10.7 to the company’s Current Report on Form 8-K filed on September 27, 2013.
|
|
|
10.34
|
ABL Credit Agreement dated as of September 25, 2013, by and among Tesoro Hawaii, LLC and other borrowers party thereto, Hawaii Pacific Energy, LLC, the Lenders party thereto and Deutsche Bank AG New York Branch, as administrative agent and ABL loan collateral agent. Incorporated by reference to Exhibit 10.9 to the company’s Current Report on Form 8-K filed on September 27, 2013.
|
|
|
10.35
|
ABL Loan Second Lien Security Agreement dated as of September 25, 2013, by and between Tesoro Hawaii, LLC and Wells Fargo Bank, National Association, as inventory collateral agent. Incorporated by reference to Exhibit 10.10 to the company’s Current Report on Form 8-K filed on September 27, 2013.
|
|
|
10.36
|
ABL Loan First Lien Security Agreement dated as of September 25, 2013, by and between Tesoro Hawaii, LLC and Deutsche Bank AG New York Branch, as ABL loan collateral agent. Incorporated by reference to Exhibit 10.11 to the company’s Current Report on Form 8-K filed on September 27, 2013.
|
|
|
10.37
|
Second Lien Mortgage dated as of September 25, 2013, by and between Tesoro Hawaii, LLC and Deutsche Bank AG New York Branch, as collateral agent. Incorporated by reference to Exhibit 10.12 to the company’s Current Report on Form 8-K filed on September 27, 2013.
|
|
|
10.38
|
Membership Interests Second Lien Pledge Agreement dated as of September 25, 2013, by and between Hawaii Pacific Energy, LLC and Deutsche Bank AG New York Branch, as ABL loan collateral agent. Incorporated by reference to Exhibit 10.13 to the company’s Current Report on Form 8-K filed on September 27, 2013.
|
|
|
10.39
|
Inventory Second Lien Security Agreement dated as of September 25, 2013, by and between Tesoro Hawaii, LLC and Deutsche Bank AG New York Branch, as collateral agent. Incorporated by reference to Exhibit 10.14 to the company’s Current Report on Form 8-K filed on September 27, 2013.
|
|
|
10.40
|
Environmental Agreement dated as of September 25, 2013, by and among Tesoro Corporation, Tesoro Hawaii, LLC and Hawaii Pacific Energy, LLC. Incorporated by reference to Exhibit 10.16 to the company’s Quarterly Report on Form 10-Q filed on November 14, 2013.
|
|
|
10.41
|
Credit Agreement dated as of November 14, 2013, by and among the company, the Lenders party thereto and Bank of Hawaii, as administrative agent for the Lenders. Incorporated by reference to Exhibit 10.1 to the company’s Current Report on Form 8-K filed on November 19, 2013.
|
|
|
14.1
|
Par Petroleum Corporation Code of Business Conduct and Ethics for Employees, Executive Officers and Directors, effective October 15, 2012. Incorporated by reference to Exhibit 14.1 to the company’s Current Report on Form 8-K filed on October 19, 2012.
|
|
|
21.1
|
Subsidiaries of the Registrant.***
|
|
|
23.1
|
Consent of Deloitte & Touche LLP***
|
|
|
23.2
|
Consent of EKS&H LLLP***
|
|
|
23.3
|
Consent of KPMG LLP***
|
|
|
23.4
|
Consent of Netherland, Sewell & Associates, Inc.***
|
48 | ||
|
31.1
|
Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. ***
|
|
|
31.2
|
Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. ***
|
|
|
32.1
|
Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350.***
|
|
|
32.2
|
Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350. ***
|
|
|
99.1
|
Report of Netherland, Sewell & Associates, Inc. regarding the registrants Proved Reserves as of December 31, 2013.***
|
|
|
99.2
|
Agreement of Settlement and Release dated September 19, 2012, by and between The Wapiti Recovery Trust and Wapiti Oil & Gas, L.L.C. Incorporated by reference to Exhibit 99.1 to the company’s Current Report on Form 8-K filed on September 25, 2013.
|
|
|
101.INS
|
XBRL Instance Document.**
|
|
|
101.SCH
|
XBRL Taxonomy Extension Schema Documents.**
|
|
|
101.CAL
|
XBRL Taxonomy Extension Calculation Linkbase Document.**
|
|
|
101.LAB
|
XBRL Taxonomy Extension Label Linkbase Document.**
|
|
|
101.PRE
|
XBRL Taxonomy Extension Presentation Linkbase Document.**
|
|
|
101.DEF
|
XBRL Taxonomy Extension Definition Linkbase Document.**
|
*
|
Management contracts and compensatory plans.
|
**
|
These interactive data files are furnished and deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.
|
***
|
Filed herewith.
|
****
|
Schedules and similar attachments to this agreement have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The company will furnish supplementally a copy of any omitted schedule or similar attachment to the Securities and Exchange Commission upon request.
|
49 | ||
|
F-1 | ||
|
/s/ EKS&H LLLP
|
|
|
EKS&H LLLP
|
|
|
F-2 | ||
|
/s/ EKS&H LLLP
|
|
|
EKS&H LLLP
|
|
|
F-3 | ||
|
/s/ KPMG LLP
|
|
|
KPMG LLP
|
|
|
F-4 | ||
|
|
|
December 31, 2013
|
|
December 31, 2012
|
|
||
ASSETS
|
|
|
|
|
|
|
|
Current assets
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
38,061
|
|
$
|
6,185
|
|
Restricted cash
|
|
|
802
|
|
|
23,970
|
|
Trade accounts receivable
|
|
|
122,913
|
|
|
17,730
|
|
Inventories
|
|
|
389,075
|
|
|
10,466
|
|
Prepaid and other current assets
|
|
|
7,522
|
|
|
1,575
|
|
Total current assets
|
|
|
558,373
|
|
|
59,926
|
|
Property and equipment
|
|
|
|
|
|
|
|
Property, plant and equipment
|
|
|
107,623
|
|
|
1,415
|
|
Proved oil and gas properties, at cost, successful efforts method of accounting
|
|
|
4,949
|
|
|
4,804
|
|
Total property and equipment
|
|
|
112,572
|
|
|
6,219
|
|
Less accumulated depreciation, depletion and amortization
|
|
|
(3,968)
|
|
|
(373)
|
|
Property and equipment, net
|
|
|
108,604
|
|
|
5,846
|
|
|
|
|
|
|
|
|
|
Long-term assets
|
|
|
|
|
|
|
|
Investments in unconsolidated affiliate
|
|
|
101,796
|
|
|
104,434
|
|
Intangible assets, net
|
|
|
11,170
|
|
|
8,809
|
|
Goodwill
|
|
|
20,603
|
|
|
7,756
|
|
Assets held for sale
|
|
|
|
|
|
2,800
|
|
Other long-term assets
|
|
|
26,539
|
|
|
11
|
|
Total assets
|
|
$
|
827,085
|
|
$
|
189,582
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
Current liabilities
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
|
$
|
3,250
|
|
$
|
35,000
|
|
Obligations under supply and exchange agreements
|
|
|
390,839
|
|
|
|
|
Accounts payable
|
|
|
28,870
|
|
|
25,329
|
|
Other accrued liabilities
|
|
|
31,956
|
|
|
981
|
|
Accrued settlement claims
|
|
|
3,793
|
|
|
8,667
|
|
Total current liabilities
|
|
|
458,708
|
|
|
69,977
|
|
Long-term liabilities
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
94,030
|
|
|
7,391
|
|
Derivative liabilities
|
|
|
17,336
|
|
|
10,945
|
|
Long-term capital lease obligations
|
|
|
1,526
|
|
|
|
|
Deferred tax liability
|
|
|
216
|
|
|
|
|
Contingent consideration liability
|
|
|
11,980
|
|
|
|
|
Other liabilities
|
|
|
6,473
|
|
|
512
|
|
Total liabilities
|
|
|
590,269
|
|
|
88,825
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies (Note 13)
|
|
|
|
|
|
|
|
Stockholders’ Equity
|
|
|
|
|
|
|
|
Preferred stock, $0.01 par value: 3,000,000 shares authorized, none issued
|
|
|
|
|
|
|
|
Common stock, $0.01 par value; 500,000,000 shares and 300,000,000 shares
authorized at December 31, 2013 and 2012, respectively, 30,151,000 shares and 15,008,092 shares issued at December 31, 2013 and 2012, respectively |
|
|
301
|
|
|
150
|
|
Additional paid-in capital
|
|
|
315,975
|
|
|
109,446
|
|
Accumulated deficit
|
|
|
(79,460)
|
|
|
(8,839)
|
|
Total stockholders’ equity
|
|
|
236,816
|
|
|
100,757
|
|
Total liabilities and stockholders’ equity
|
|
$
|
827,085
|
|
$
|
189,582
|
|
F-5 | ||
|
|
|
Successor
|
|
|
Predecessor
|
|
|||||
|
|
|
|
|
|
September 1
|
|
|
|
January 1, 2012
|
|
|
|
Year Ended
|
|
|
through
|
|
|
|
through
|
|
|
|
|
December 31, 2013
|
|
|
December 31, 2012
|
|
|
|
August 31, 2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
Refining, distribution and marketing revenues
|
|
$
|
778,126
|
|
$
|
|
|
|
$
|
|
|
Commodity marketing and logistics revenues
|
|
|
100,149
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
|
7,739
|
|
|
2,144
|
|
|
|
23,079
|
|
Total operating revenues
|
|
|
886,014
|
|
|
2,144
|
|
|
|
23,079
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
Cost of revenues
|
|
|
848,924
|
|
|
|
|
|
|
|
|
Operating expense, excluding depreciation, depletion
and amortization expense shown separately below |
|
|
27,251
|
|
|
|
|
|
|
|
|
Lease operating expense
|
|
|
5,627
|
|
|
1,684
|
|
|
|
9,038
|
|
Transportation expense
|
|
|
|
|
|
|
|
|
|
6,963
|
|
Production taxes
|
|
|
49
|
|
|
4
|
|
|
|
979
|
|
Exploration expense
|
|
|
|
|
|
|
|
|
|
2
|
|
Dry hole costs and impairments
|
|
|
|
|
|
|
|
|
|
151,347
|
|
Depreciation, depletion and amortization
|
|
|
5,982
|
|
|
401
|
|
|
|
16,041
|
|
Trust litigation and settlements
|
|
|
6,206
|
|
|
|
|
|
|
|
|
General and administrative expense
|
|
|
21,494
|
|
|
4,520
|
|
|
|
9,386
|
|
Acquisition and integration costs
|
|
|
9,794
|
|
|
556
|
|
|
|
|
|
Total operating expenses
|
|
|
925,327
|
|
|
7,165
|
|
|
|
193,756
|
|
Operating loss
|
|
|
(39,313)
|
|
|
(5,021)
|
|
|
|
(170,677)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income and (expense):
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense and financing costs, net
|
|
|
(19,471)
|
|
|
(1,056)
|
|
|
|
(6,852)
|
|
Other income
|
|
|
808
|
|
|
86
|
|
|
|
516
|
|
Change in value of common stock warrants
|
|
|
(10,114)
|
|
|
(4,280)
|
|
|
|
|
|
Gain on derivative instruments, net
|
|
|
410
|
|
|
|
|
|
|
|
|
Loss from unconsolidated affiliates
|
|
|
(2,941)
|
|
|
(1,325)
|
|
|
|
(20)
|
|
Total other expense
|
|
|
(31,308)
|
|
|
(6,575)
|
|
|
|
(6,356)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before income taxes and reorganization items
|
|
|
(70,621)
|
|
|
(11,596)
|
|
|
|
(177,033)
|
|
Income tax benefit
|
|
|
|
|
|
(2,757)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before reorganization items
|
|
|
(70,621)
|
|
|
(8,839)
|
|
|
|
(177,033)
|
|
Reorganization items
|
|
|
|
|
|
|
|
|
|
|
|
Professional fees and administrative costs
|
|
|
|
|
|
|
|
|
|
22,354
|
|
Changes in asset fair values due to fresh start accounting
adjustments |
|
|
|
|
|
|
|
|
|
14,765
|
|
Gain on settlement of senior debt
|
|
|
|
|
|
|
|
|
|
(166,144)
|
|
Gain on settlement of liabilities
|
|
|
|
|
|
|
|
|
|
(2,571)
|
|
Net loss
|
|
$
|
(70,621)
|
|
$
|
(8,839)
|
|
|
$
|
(45,437)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic loss per common share
|
|
$
|
(3.57)
|
|
$
|
(0.56)
|
|
|
$
|
(1.57)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted loss per common share
|
|
$
|
(3.57)
|
|
$
|
(0.56)
|
|
|
$
|
(1.57)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
19,740
|
|
|
15,734
|
|
|
|
28,841
|
|
Diluted
|
|
|
19,740
|
|
|
15,734
|
|
|
|
28,841
|
|
F-6 | ||
|
|
|
|
|
|
|
|
|
Additional
|
|
|
|
|
|
|
|
|
|
|
Common Stock
|
|
paid-in
|
|
Accumulated
|
|
Total
|
|
|||||||
|
Shares
|
|
Amount
|
|
capital
|
|
Deficit
|
|
Equity
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, January 1, 2012 (Predecessor)
|
|
|
28,841
|
|
$
|
288
|
|
$
|
1,641,390
|
|
$
|
(1,591,453)
|
|
$
|
50,225
|
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
(45,437)
|
|
|
(45,437)
|
|
Forfeitures
|
|
|
(58)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation
|
|
|
|
|
|
|
|
|
1,895
|
|
|
|
|
|
1,895
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, August 31, 2012 (Predecessor)
|
|
|
28,783
|
|
|
288
|
|
|
1,643,285
|
|
|
(1,636,890)
|
|
|
6,683
|
|
Cancellation of predecessor common stock
|
|
|
(28,783)
|
|
|
(288)
|
|
|
288
|
|
|
|
|
|
|
|
Elimination of predecessor accumulated deficit
|
|
|
|
|
|
|
|
|
(1,636,890)
|
|
|
1,636,890
|
|
|
|
|
Issuance of common stock and fresh start accounting
upon emergence from Chapter 11 |
|
|
14,766
|
|
|
148
|
|
|
102,731
|
|
|
|
|
|
102,879
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, August 31, 2012 (Successor)
|
|
|
14,766
|
|
|
148
|
|
|
109,414
|
|
|
|
|
|
109,562
|
|
Stock issued to settle bankruptcy claims
|
|
|
20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation
|
|
|
222
|
|
|
2
|
|
|
32
|
|
|
|
|
|
34
|
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
(8,839)
|
|
|
(8,839)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2012 (Successor)
|
|
|
15,008
|
|
|
150
|
|
|
109,446
|
|
|
(8,839)
|
|
|
100,757
|
|
Stock issued in a private transaction, net of offering cost of $830
|
|
|
14,388
|
|
|
144
|
|
|
199,026
|
|
|
|
|
|
199,170
|
|
Stock issued to settle bankruptcy claims
|
|
|
209
|
|
|
2
|
|
|
2,603
|
|
|
|
|
|
2,605
|
|
Stock issued through exercise of warrants
|
|
|
184
|
|
|
2
|
|
|
3,739
|
|
|
|
|
|
3,741
|
|
Stock-based compensation
|
|
|
362
|
|
|
3
|
|
|
1,161
|
|
|
|
|
|
1,164
|
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
(70,621)
|
|
|
(70,621)
|
|
Balance, December 31, 2013 (Successor)
|
|
|
30,151
|
|
$
|
301
|
|
$
|
315,975
|
|
$
|
(79,460)
|
|
$
|
236,816
|
|
F-7 | ||
|
|
|
Successor
|
|
|
Predecessor
|
|
|||||
|
|
Year Ended
December 31, 2013 |
|
September 1
through December 31, 2012 |
|
|
January 1
through August 31, 2012 |
|
|||
CASH FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(70,621)
|
|
$
|
(8,839)
|
|
|
$
|
(45,437)
|
|
Adjustments to reconcile net loss to cash provided by (used in)
operating activities: |
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion, amortization and accretion
|
|
|
5,982
|
|
|
401
|
|
|
|
16,041
|
|
Non cash interest expense
|
|
|
16,742
|
|
|
1,056
|
|
|
|
2,989
|
|
Change in asset values due to fresh - start accounting
adjustments |
|
|
|
|
|
|
|
|
|
14,765
|
|
Gain on extinguishment of senior debt
|
|
|
|
|
|
|
|
|
|
(166,144)
|
|
Gain on settlement of liabilities
|
|
|
|
|
|
|
|
|
|
(2,188)
|
|
(Gain) loss on property sales
|
|
|
(50)
|
|
|
(82)
|
|
|
|
126
|
|
Dry hole costs and impairments
|
|
|
|
|
|
|
|
|
|
151,347
|
|
Stock-based compensation
|
|
|
1,161
|
|
|
34
|
|
|
|
1,895
|
|
Change in value of common stock warrants
|
|
|
10,114
|
|
|
4,280
|
|
|
|
|
|
Loss from unconsolidated affiliates
|
|
|
2,941
|
|
|
1,325
|
|
|
|
20
|
|
Deferred income tax expense (benefit)
|
|
|
179
|
|
|
(2,757)
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
(699)
|
|
Net changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
Trade accounts receivable
|
|
|
(45,698)
|
|
|
(2,234)
|
|
|
|
3,472
|
|
Prepaids and other current assets
|
|
|
(2,569)
|
|
|
(538)
|
|
|
|
(1,378)
|
|
Inventories
|
|
|
40,141
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
|
15,829
|
|
|
2,718
|
|
|
|
(4,187)
|
|
Supply and exchange agreements
|
|
|
(13,061)
|
|
|
|
|
|
|
|
|
Settlement liability
|
|
|
1,898
|
|
|
|
|
|
|
|
|
Accrued reorganization costs
|
|
|
|
|
|
|
|
|
|
9,116
|
|
Other accrued liabilities
|
|
|
1,335
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in operating activities
|
|
|
(35,677)
|
|
|
(4,636)
|
|
|
|
(20,262)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(7,768)
|
|
|
|
|
|
|
(1,613)
|
|
Acquisitions, net of cash acquired
|
|
|
(559,279)
|
|
|
(17,439)
|
|
|
|
|
|
Proceeds from asset sales
|
|
|
2,850
|
|
|
|
|
|
|
74,209
|
|
Proceeds from sale of other fixed assets
|
|
|
|
|
|
39
|
|
|
|
26
|
|
Capitalized drilling costs paid to operator
|
|
|
(303)
|
|
|
(415)
|
|
|
|
|
|
Proceeds from sale of unconsolidated affiliates
|
|
|
|
|
|
125
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash (used in) provided by investing activities
|
|
|
(564,500)
|
|
|
(17,690)
|
|
|
|
72,622
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
Funding of purchase of HIE from supply and exchange
agreements |
|
|
378,238
|
|
|
|
|
|
|
|
|
Proceeds from sale of common stock, net of offering costs
|
|
|
199,170
|
|
|
|
|
|
|
|
|
Proceeds from exercise of common stock warrants
|
|
|
18
|
|
|
|
|
|
|
|
|
Proceeds from borrowings
|
|
|
159,800
|
|
|
35,000
|
|
|
|
23,000
|
|
Repayments of borrowings
|
|
|
(121,909)
|
|
|
|
|
|
|
(59,535)
|
|
Payment of deferred loan costs
|
|
|
(2,264)
|
|
|
|
|
|
|
|
|
Fund distribution agent account
|
|
|
|
|
|
|
|
|
|
(21,805)
|
|
Proceeds from (funding of) Wapiti and General Recovery
Trusts |
|
|
|
|
|
2,446
|
|
|
|
(2,000)
|
|
Recoveries from bankruptcy settlements
|
|
|
|
|
|
5,183
|
|
|
|
|
|
Restricted cash released from (held to) secure letter of credits
|
|
|
19,000
|
|
|
(19,000)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities
|
|
|
632,053
|
|
|
23,629
|
|
|
|
(60,340)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
31,876
|
|
|
1,303
|
|
|
|
(7,980)
|
|
Cash at beginning of period
|
|
|
6,185
|
|
|
4,882
|
|
|
|
12,862
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash at end of period
|
|
$
|
38,061
|
|
$
|
6,185
|
|
|
$
|
4,882
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTAL CASH FLOW INFORMATION
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for interest and financing costs
|
|
$
|
2,186
|
|
$
|
|
|
|
$
|
3,745
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NON-CASH INVESTING AND FINANCING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
Stock issued used to settle bankruptcy claims
|
|
$
|
2,605
|
|
$
|
|
|
|
$
|
|
|
Interest payable capitalized to principal balance
|
|
$
|
6,096
|
|
$
|
|
|
|
$
|
|
|
Non-cash additions to property, plant and equipment
|
|
$
|
|
|
$
|
209
|
|
|
$
|
|
|
F-8 | ||
|
F-9 | ||
|
F-10 | ||
|
Assets
|
|
Lives in Years
|
|
Refining
|
|
8 to 47
|
|
Logistic
|
|
3 to 30
|
|
Retail
|
|
14 to 18
|
|
Corporate
|
|
3 to 7
|
|
Software
|
|
3
|
|
F-11 | ||
|
F-12 | ||
|
F-13 | ||
|
|
|
|
|
|
September 1
|
|
|
|
|
Year Ended
|
|
through
|
|
||
|
|
December 31, 2013
|
|
December 31, 2012
|
|
||
Beginning balance
|
|
$
|
104,434
|
|
$
|
105,344
|
|
Loss from unconsolidated affiliates
|
|
|
(3,516)
|
|
|
(1,325)
|
|
Accretion of basis difference
|
|
|
575
|
|
|
|
|
Capitalized drilling costs obligation paid
|
|
|
303
|
|
|
415
|
|
Ending balance
|
|
$
|
101,796
|
|
$
|
104,434
|
|
|
|
December 31, 2013
|
|
December 31, 2012
|
|
||
Assets
|
|
|
|
|
|
|
|
Current assets
|
|
$
|
5,901
|
|
$
|
6,275
|
|
Non-current assets
|
|
|
454,402
|
|
|
460,991
|
|
Current liabilities
|
|
|
(13,040)
|
|
|
(11,826)
|
|
Non-current liabilities
|
|
|
(96,738)
|
|
|
(94,369)
|
|
|
|
Year Ended
|
|
September 1 through
|
|
||
|
|
December 31, 2013
|
|
December 31, 2012
|
|
||
|
|
100%
|
|
100%
|
|
||
Oil, natural gas and natural gas liquids
revenues |
|
$
|
61,091
|
|
$
|
19,391
|
|
Loss from operations
|
|
|
(6,765)
|
|
|
(2,095)
|
|
Net loss
|
|
|
(10,546)
|
|
|
(3,975)
|
|
F-14 | ||
|
Intangible assets
|
|
$
|
8,809
|
|
Goodwill
|
|
|
6,990
|
|
Net non cash-working capital
|
|
|
3,097
|
|
Deferred tax liabilities
|
|
|
(2,757)
|
|
|
|
|
|
|
Total, net of cash acquired
|
|
$
|
16,139
|
|
F-15 | ||
|
Inventory
|
|
$
|
418,750
|
|
Trade accounts receivable
|
|
|
59,485
|
|
Prepaids and other current assets
|
|
|
1,978
|
|
Property, plant and equipment
|
|
|
58,782
|
|
Land
|
|
|
39,800
|
|
Goodwill
|
|
|
13,613
|
|
Intangible assets
|
|
|
4,689
|
|
Accounts payable and other current liabilities
|
|
|
(18,154)
|
|
Contingent consideration liability
|
|
|
(11,980)
|
|
Other noncurrent liabilities
|
|
|
(6,384)
|
|
|
|
|
|
|
Total
|
|
$
|
560,579
|
|
|
|
2013
|
|
2012
|
|
||
(in millions)
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
2,986.8
|
|
$
|
3,811.1
|
|
Net loss
|
|
$
|
(113.6)
|
|
$
|
(12.0)
|
|
F-16 | ||
|
|
|
December 31,
|
|
||||
|
|
2013
|
|
2012
|
|
||
Land
|
|
$
|
39,800
|
|
$
|
|
|
Buildings and equipment
|
|
|
65,878
|
|
|
|
|
Other
|
|
|
1,945
|
|
|
1,415
|
|
Property, plant and equipment
|
|
|
107,623
|
|
|
1,415
|
|
Proved oil and gas properties
|
|
|
4,949
|
|
|
4,804
|
|
Less: accumulated depreciation, depletion
and amortization |
|
|
(3,968)
|
|
|
(373)
|
|
|
|
$
|
108,604
|
|
$
|
5,846
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|||||
|
|
|
|
|
September 1
|
|
|
January 1
|
|
||
|
|
Year Ended
|
|
through
|
|
|
through
|
|
|||
|
|
December 31, 2013
|
|
December 31, 2012
|
|
|
August 31, 2012
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation
beginning of period |
|
$
|
512
|
|
$
|
476
|
|
|
$
|
3,799
|
|
Obligation acquired
|
|
|
2,601
|
|
|
|
|
|
|
|
|
Accretion expense
|
|
|
59
|
|
|
36
|
|
|
|
178
|
|
Change in estimate
|
|
|
|
|
|
|
|
|
|
437
|
|
Settlement upon transfer to
Piceance Energy |
|
|
|
|
|
|
|
|
|
(3,938)
|
|
Asset retirement obligation
end of period |
|
$
|
3,172
|
|
$
|
512
|
|
|
$
|
476
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
December 31, 2013
|
|
|
2012
|
|
|||||||
|
|
|
|
|
|
Supply and
|
|
|
|
|
|
|
|
|
|
|
Titled
|
|
|
Exchange
|
|
|
|
|
|
|
|
|
|
|
Inventory
|
|
|
Agreements
|
|
|
Total
|
|
|
Titled Inventory
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil and feedstocks
|
|
$
|
|
|
$
|
146,158
|
|
$
|
146,158
|
|
$
|
10,466
|
|
Refined products and blend stock
|
|
|
67,532
|
|
|
161,554
|
|
|
229,086
|
|
|
|
|
Spare parts, materials and supplies, and merchandise
|
|
|
13,831
|
|
|
|
|
|
13,831
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
81,363
|
|
$
|
307,712
|
|
$
|
389,075
|
|
$
|
10,466
|
|
F-17 | ||
|
|
|
December 31,
|
|
||||
|
|
2013
|
|
2012
|
|
||
Amortized intangible assets:
|
|
|
|
|
|
|
|
Gross carrying amount:
|
|
|
|
|
|
|
|
Supplier relationships
|
|
$
|
3,360
|
|
$
|
3,360
|
|
Rail car leases
|
|
|
3,249
|
|
|
3,249
|
|
Historical shipper status
|
|
|
2,200
|
|
|
2,200
|
|
Trade names and trademarks
|
|
|
4,689
|
|
|
|
|
Subtotal
|
|
|
13,498
|
|
|
8,809
|
|
Accumulated amortization
|
|
|
|
|
|
|
|
Supplier relationships
|
|
|
(258)
|
|
|
|
|
Rail car leases
|
|
|
(650)
|
|
|
|
|
Historical shipper status
|
|
|
(1,100)
|
|
|
|
|
Trade name and trademarks
|
|
|
(320)
|
|
|
|
|
Subtotal
|
|
|
(2,328)
|
|
|
|
|
Net:
|
|
|
|
|
|
|
|
Supplier relationships
|
|
|
3,102
|
|
|
3,360
|
|
Rail car leases
|
|
|
2,599
|
|
|
3,249
|
|
Historical shipper status
|
|
|
1,100
|
|
|
2,200
|
|
Trade name and trademarks
|
|
|
4,369
|
|
|
|
|
Total amortized intangible assets, net
|
|
$
|
11,170
|
|
$
|
8,809
|
|
Year Ended
|
|
Amount
|
|
|
|
|
|
|
|
2014
|
|
$
|
3,571
|
|
2015
|
|
|
2,471
|
|
2016
|
|
|
2,151
|
|
2017
|
|
|
908
|
|
2018
|
|
|
258
|
|
Thereafter
|
|
|
1,811
|
|
|
|
$
|
11,170
|
|
Balance at beginning of period
|
|
$
|
7,756
|
|
Additions
|
|
|
13,613
|
|
Texadian purchase price adjustments
|
|
|
(766)
|
|
Balance at end of period
|
|
$
|
20,603
|
|
F-18 | ||
|
|
|
December 31,
|
|
||||
|
|
2013
|
|
2012
|
|
||
Tranche B Loan
|
|
$
|
19,480
|
|
$
|
35,000
|
|
Delayed Draw Term Loan Agreement
|
|
|
|
|
|
13,465
|
|
ABL Facility
|
|
|
51,800
|
|
|
|
|
Retail Credit Agreement
|
|
|
26,000
|
|
|
|
|
Less: unamortized debt discount warrants
|
|
|
|
|
|
(6,014)
|
|
Less: unamortized debt discount embedded derivative
|
|
|
|
|
|
(60)
|
|
|
|
|
|
|
|
|
|
Total debt, net of unamortized debt discount
|
|
|
97,280
|
|
|
42,391
|
|
Less: current maturities
|
|
|
(3,250)
|
|
|
(35,000)
|
|
|
|
|
|
|
|
|
|
Long-term debt, net of current maturities and unamortized discount
|
|
$
|
94,030
|
|
$
|
7,391
|
|
Year
|
|
|
Amount Due
|
|
|
|
|
|
|
2014
|
|
$
|
3,250
|
|
2015
|
|
|
2,600
|
|
2016
|
|
|
22,080
|
|
2017
|
|
|
54,400
|
|
2018
|
|
|
2,600
|
|
Thereafter
|
|
|
12,350
|
|
|
|
|
|
|
|
|
$
|
97,280
|
|
F-19 | ||
|
F-20 | ||
|
Period (during and as of the last day of)
|
|
Maximum Leverage Ratio
|
|
2013 Fiscal Year
|
|
5.75 to 1.00
|
|
2014 Fiscal Year
|
|
5.50 to 1.00
|
|
2015 Fiscal Year
|
|
5.25 to 1.00
|
|
2016 Fiscal Year
|
|
5.00 to 1.00
|
|
2017 Fiscal Year, and at all times thereafter
|
|
4.75 to 1.00
|
|
Level
|
|
Leverage Ratio
|
|
Applicable Margin for
LIBOR Loans |
|
|
Applicable Margin for Base
Rate Loans |
|
1
|
|
<4.00x
|
|
2
|
%
|
|
0
|
%
|
2
|
|
4.00x-5.00x
|
|
2.25
|
%
|
|
.25
|
%
|
3
|
|
>5.00x
|
|
2.5
|
%
|
|
.50
|
%
|
F-21 | ||
|
|
|
|
|
|
|
Revolver
|
|
Revolver
|
|
|
|
|
|
|
|
Applicable Margin for
|
|
Applicable Margin for
|
|
Level
|
|
Leverage Ratio
|
|
Unused Fee
|
|
LIBOR Loans
|
|
Base Rate Loans
|
|
1
|
|
<4.00x
|
|
.25
|
%
|
1.75
|
%
|
-.25
|
%
|
2
|
|
4.00x-5.00x
|
|
.375
|
%
|
2.00
|
%
|
0
|
%
|
3
|
|
>5.00x
|
|
.50
|
%
|
2.25
|
%
|
.25
|
%
|
F-22 | ||
|
|
Level 1
|
Assets or liabilities for which the item is valued based on quoted prices (unadjusted) for identical assets or liabilities in active markets.
|
|
Level 2
|
Assets or liabilities valued based on observable market data for similar instruments.
|
|
Level 3
|
Assets or liabilities for which significant valuation assumptions are not readily observable in the market; instruments valued based on the best available data, some of which is internally-developed, and considers risk premiums that a market participant would require.
|
F-23 | ||
|
|
|
Fair Value at
|
|
Fair Value
|
|
|
|
|
August 31, 2012
|
|
Technique
|
|
|
|
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas properties
|
|
|
|
|
|
|
Proved
|
|
$
|
4,587
|
|
(a)(b)
|
|
Other assets
|
|
|
|
|
|
|
Frac tanks
|
|
|
1,400
|
|
(c)
|
|
Compressors
|
|
|
2,800
|
|
(c)
|
|
Miscellaneous
|
|
|
39
|
|
(d)
|
|
|
|
|
|
|
|
|
Investment in Piceance Energy
|
|
|
105,344
|
|
(e)
|
|
(a)
|
Certain proved property was valued using the cost valuation technique. A significant input in this measurement was the estimated cost of the properties. A change in that estimated cost would be directly correlated to change in the estimated fair value of the property. We consider this to be a Level 3 fair value measurement.
|
(b)
|
The estimated fair value of our Point Arguello Unit offshore California was valued using a market valuation technique based on standalone bids received by third-parties during the sale process. We consider this to be a Level 2 fair value measurement.
|
(c)
|
The estimated fair value of our frac tanks and compressor units was valued using a market valuation technique which was based on published listings of similar equipment or standalone bids received by third-parties. We consider these to be Level 2 fair value measurements.
|
(d)
|
Miscellaneous assets (assets that we were unable to value using the income or market valuation techniques) were valued using the cost valuation technique. We consider this to be a Level 3 fair value measurement.
|
(e)
|
The estimated fair value of our investment in Piceance Energy was based on its enterprise value and uses various valuation techniques including (i) an income approach based on proved developed reserves’ future net income discounted back to net present value based on the weighted average cost of capital for comparable independent oil and natural gas producers, and (ii) a market multiple approach. Proved property was valued using the income approach. A discounted cash flow model was prepared based off of an independent reserve report with a discount rate of
10
% applied to proved developed producing reserves,
15
% to proved developed non-producing reserves and
20
% to proved undeveloped reserves. The prices for oil and natural gas were forecasted based on NYMEX strip pricing adjusted for basis differentials. For the market multiple approach, we reviewed the transaction values of recent similar asset transactions and compared the purchase price per Mcfe of proved developed reserves and purchase price per Mcfe per day of net equivalent production of those transactions to the independent reserve report. Unproved acreage was valued using a cost approach based on recent sales of acreage in the area. Based on these valuations, the equity value of our
33.34
% interest in Piceance Energy was estimated to be approximately $
105.3
million on the Emergence date. We consider this to be a Level 3 fair value measurement.
|
|
|
Fair Value at
|
|
Fair Value
|
|
|
|
|
December 31, 2012
|
|
Technique
|
|
|
|
|
(in thousands)
|
|
|
|
|
Net non-cash working capital
|
|
$
|
3,631
|
|
(a)
|
|
Supplier relationship
|
|
|
3,360
|
|
(b)
|
|
Historical shipper status
|
|
|
2,200
|
|
(c)
|
|
Railcar leases
|
|
|
3,249
|
|
(d)
|
|
Goodwill
|
|
|
7,756
|
|
(e)
|
|
Deferred tax liabilities
|
|
|
(2,757)
|
|
(f)
|
|
|
|
$
|
17,439
|
|
|
|
(a)
|
Current assets acquired and liabilities assumed were recorded at their net realizable value.
|
(b)
|
The estimated fair value of the supplier relationship was estimated using a form of the income approach, the Multiple-Period Excess Earnings Method. Significant inputs used in this model include estimated cash flows from the suppliers, customer growth and rates and a discount rate. An increase in the cash flows attributable to the supplier relationships would result in an increase in the value of such relationship, while an increase in the discount rate would result in a decrease in the value. We consider this to be a Level 3 fair value measurement.
|
F-24 | ||
|
(c)
|
The estimated fair value of the historical shipper status was estimated using a form of the income approach, the Greenfield Method. Significant inputs used in this model include estimated cash flows with and without the historical shipper status, and a discount rate. An increase in the cash flows attributable to the shipper would result in an increase in the value of such relationship, while an increase in the discount rate would result in a decrease in the value. We consider this to be a Level 3 fair value measurement.
|
(d)
|
The estimated fair value of the railcar leases was estimated using a form of the income approach, the Lost Income Method. Significant inputs used in this model include the cost of providing services with and without the favorable railcar leases and a discount rate. An increase in market rates of railcar leases would result in an increase in the value attributable to the acquired leases. We consider this to be a Level 3 fair value measurement.
|
(e)
|
The excess of the purchase price paid over the fair value of the identifiable assets acquired and liabilities assumed is allocated to goodwill.
|
(f)
|
A deferred tax liability has been recorded since the acquired intangible assets will not be deductible for tax purposes until the eventual sale of the company.
|
|
|
Fair Value at
|
|
Fair Value
|
|
|
|
|
September 25, 2013
|
|
Technique
|
|
|
|
|
(in thousands)
|
|
|
|
|
Net working capital
|
|
$
|
462,059
|
|
(a)
|
|
Property, plant and equipment
|
|
|
58,782
|
|
(b)
|
|
Land
|
|
|
39,800
|
|
(c)
|
|
Trade names and trade marks
|
|
|
4,689
|
|
(d)
|
|
Goodwill
|
|
|
13,613
|
|
(e)
|
|
Contingent consideration liability
|
|
|
(11,980)
|
|
(f)
|
|
Other noncurrent liabilities
|
|
|
(6,384)
|
|
(g)
|
|
|
|
|
|
|
|
|
|
|
$
|
560,579
|
|
|
|
|
(a)
|
Current assets acquired and liabilities assumed were recorded at their net realizable value.
|
|
(b)
|
The estimated fair value of the property, plant and equipment was estimated using the cost approach. Under the cost approach, the total replacement cost of the property is determined based on industry sources with adjustments for regional factors. The total cost is then adjusted for depreciation based on the physical age of the assets and external obsolescence. We consider this to be a Level 3 fair value measurement.
|
|
(c)
|
The estimated fair value of the land was estimated using the sales comparison approach. Under this approach, the sales prices of similar properties are adjusted to account for differences in land characteristics. We consider this to be a Level 3 fair value measurement.
|
|
(d)
|
The estimated fair value of the trade names and trademarks was estimated using a form of the income approach, the Relief from Royalty Method. Significant inputs used in this model include estimated revenue attributable to the trade names and trademarks and a royalty rate. An increase in the estimated revenue or royalty rate would result in an increase in the value attributable to the trade names and trademarks. We consider this to be a Level 3 fair value measurement.
|
|
(e)
|
The excess of the purchase price paid over the fair value of the identifiable assets acquired and liabilities assumed is allocated to goodwill.
|
|
(f)
|
The estimated fair value of the liability for contingent consideration was estimated using Monte Carlo Simulation. Significant inputs used in the model include estimated future gross margin, annual gross margin volatility and a present value factor. An increase in estimated future gross margin, volatility or the present value factor would result in an increase in the liability. We consider this to be a Level 3 fair value measurement.
|
|
(g)
|
Other noncurrent assets and liabilities are recorded at their estimated net present value as estimated by management.
|
F-25 | ||
|
|
|
December 31,
|
|
||||
|
|
2013
|
|
2012
|
|
||
|
|
|
|
|
|
|
|
Stock price
|
|
$
|
22.30
|
|
$
|
12.00
|
|
Initial exercise price
|
|
$
|
0.1
|
|
$
|
0.1
|
|
Term (years)
|
|
|
8.67
|
|
|
9.67
|
|
Risk-free rate
|
|
|
2.78
|
%
|
|
1.68
|
%
|
Expected volatility
|
|
|
52.9
|
%
|
|
75.0
|
%
|
|
|
Location on
|
|
|
|
|
|
|
|
|
|
Consolidated
|
|
|
Fair Value at
|
|
Fair Value at
|
|
|
|
|
Balance Sheet
|
|
December 31, 2013
|
|
December 31, 2012
|
|
||
|
|
|
|
|
|
|
|
|
|
Commodities physical forward
contracts |
|
Prepaid and other current assets
|
|
$
|
|
|
$
|
(307)
|
|
Commodities exchange traded
futures |
|
Prepaid and other current assets
|
|
|
|
|
|
542
|
|
Warrant derivatives
|
|
Derivative liabilities
|
|
|
(17,336)
|
|
|
(10,900)
|
|
Contingent consideration liability
|
|
Contingent consideration liability
|
|
|
(11,980)
|
|
|
|
|
Debt repayment derivative
|
|
Derivative liabilities
|
|
|
|
|
|
(45)
|
|
F-26 | ||
|
|
|
|
|
|
|
|
September 1
|
|
|
|
|
|
|
|
|
through
|
|
||
|
|
|
|
December 31, 2013
|
|
December 31, 2012
|
|
||
|
|
|
|
Gain (loss)
|
|
Gain (loss)
|
|
||
|
|
Income Statement
|
|
recognized in
|
|
recognized in
|
|
||
|
|
Classification
|
|
income
|
|
income
|
|
||
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as
hedges: |
|
|
|
|
|
|
|
|
|
Warrants
|
|
Change in value
of warrants |
|
$
|
(10,114)
|
|
$
|
(4,280)
|
|
Debt repayment derivative
|
|
Interest expense and
financing costs, net |
|
|
45
|
|
|
|
|
Commodities - exchange traded
futures |
|
Gain on derivative
instruments, net |
|
|
104
|
|
|
|
|
Commodities - physical forward
contracts |
|
Gain on derivative
instruments, net |
|
|
306
|
|
|
|
|
|
|
December 31, 2013
|
|
||||||||||
|
|
Fair Value
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Warrants derivative
|
|
$
|
(17,336)
|
|
$
|
|
|
$
|
|
|
$
|
(17,336)
|
|
Contingent consideration liability
|
|
|
(11,980)
|
|
|
|
|
|
|
|
|
(11,980)
|
|
|
|
$
|
(29,316)
|
|
$
|
|
|
$
|
|
|
$
|
(29,316)
|
|
|
|
December 31, 2012
|
|
||||||||||
|
|
Fair Value
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
||||
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodities exchange traded futures
|
|
$
|
542
|
|
$
|
542
|
|
$
|
|
|
$
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Warrants derivative
|
|
$
|
(10,900)
|
|
$
|
|
|
$
|
|
|
$
|
(10,900)
|
|
Debt prepayment derivative
|
|
|
(45)
|
|
|
|
|
|
|
|
|
(45)
|
|
Commodities physical forward contracts
|
|
|
(307)
|
|
|
|
|
|
(307)
|
|
|
|
|
|
|
$
|
(11,252)
|
|
$
|
|
|
$
|
(307)
|
|
$
|
(10,945)
|
|
Description
|
|
2013
|
|
2012
|
|
||
|
|
|
|
|
|
|
|
Balance, at beginning of period
|
|
$
|
(10,945)
|
|
$
|
(6,665)
|
|
Settlements
|
|
|
3,723
|
|
|
|
|
Acquired
|
|
|
(11,980)
|
|
|
|
|
Total unrealized losses included in earnings
|
|
|
(10,114)
|
|
|
(4,280)
|
|
Transfers
|
|
|
|
|
|
|
|
Balance, at end of period
|
|
$
|
(29,316)
|
|
$
|
(10,945)
|
|
F-27 | ||
|
|
|
December 31, 2013
|
|
||||
|
|
Carrying Value
|
|
Fair Value
(1)
|
|
||
Tranche B
|
|
$
|
19,480
|
|
$
|
18,800
|
|
ABL Facility
|
|
|
51,800
|
|
|
51,800
|
|
HIE Retail Credit Agreement
|
|
|
26,000
|
|
|
26,000
|
|
Warrants
|
|
|
17,336
|
|
|
17,336
|
|
Contingent consideration liability
|
|
|
11,980
|
|
|
11,980
|
|
|
|
December 31, 2012
|
|
||||
|
|
Carrying Value
|
|
Fair Value
(1)
|
|
||
Long-term debt
|
|
$
|
7,391
|
|
$
|
10,900
|
|
Warrants
|
|
|
10,900
|
|
|
10,900
|
|
Debt repayment derivative
|
|
|
45
|
|
|
45
|
|
F-28 | ||
|
F-29 | ||
|
F-30 | ||
|
|
Emergence-Date
August 31, 2012 |
|
From Emergence-Date through December 31, 2012
|
|
|||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
Remaining Filed
|
|
|||||||
|
Filed Claims
|
|
Settled Claims
|
|
Claims
|
|
|||||||||||||||
|
|
|
|
|
|
|
|
|
Consideration
|
|
|
|
|
|
|||||||
|
Count
|
|
Amount
|
|
Count
|
|
Amount
|
|
Cash
|
|
Stock
|
|
Count
|
|
Amount
|
|
|||||
U.S. Government Claims
|
|
3
|
|
$
|
22,364
|
|
|
|
$
|
|
|
$
|
|
|
|
|
3
|
|
$
|
22,364
|
|
Former Employee Claims
|
|
32
|
|
|
16,380
|
|
13
|
|
|
3,685
|
|
|
230
|
|
20
|
|
19
|
|
|
12,695
|
|
Macquarie Capital (USA) Inc.
|
|
1
|
|
|
8,672
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
8,672
|
|
Swann and BuzzardCreek
RoyaltyTrust |
|
1
|
|
|
3,200
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
3,200
|
|
Other Various Claims*
|
|
75
|
|
|
23,114
|
|
12
|
|
|
2,915
|
|
|
29
|
|
|
|
63
|
|
|
20,199
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
112
|
|
$
|
73,730
|
|
25
|
|
$
|
6,600
|
|
$
|
259
|
|
20
|
|
87
|
|
$
|
67,130
|
|
|
|
For the Year Ended December 31, 2013
|
|
||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
Remaining Filed
|
|
|||
|
|
Settled Claims
|
|
Claims
|
|
||||||||||||
|
|
|
|
|
|
|
Consideration
|
|
|
|
|
|
|
||||
|
|
Count
|
|
Amount
|
|
Cash
|
|
Stock
|
|
Count
|
|
|
Amount
|
|
|||
U.S. Government Claims
|
|
1
|
|
$
|
|
|
$
|
|
|
|
|
|
2
|
|
$
|
22,364
|
|
Former Employee Claims
|
|
19
|
|
|
12,695
|
|
|
340
|
|
|
162
|
|
|
|
|
|
|
Macquarie Capital (USA) Inc.
|
|
1
|
|
|
8,672
|
|
|
2,500
|
|
|
|
|
|
|
|
|
|
Swann and Buzzard Creek Royalty Trust
|
|
1
|
|
|
3,200
|
|
|
2,000
|
|
|
|
|
|
|
|
|
|
Other Various Claims
(1)
|
|
37
|
|
|
2,339
|
|
|
543
|
|
|
47
|
|
26
|
|
|
17,860
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
59
|
|
$
|
26,906
|
|
$
|
5,383
|
|
|
209
|
|
28
|
|
$
|
40,224
|
|
|
(1)
|
Includes reserve for contingent/unliquidated claims in the amount of $
10
million.
|
2014
|
|
$
|
382
|
|
2015
|
|
|
382
|
|
2016
|
|
|
382
|
|
2017
|
|
|
382
|
|
2018
|
|
|
420
|
|
Thereafter
|
|
|
420
|
|
Total minimum lease payments
|
|
|
2,368
|
|
Less amount representing interest
|
|
|
634
|
|
|
|
|
|
|
Total minimum rental payments
|
|
$
|
1,734
|
|
F-31 | ||
|
2014
|
|
$
|
22,724
|
|
2015
|
|
|
13,277
|
|
2016
|
|
|
12,362
|
|
2017
|
|
|
10,375
|
|
2018
|
|
|
9,244
|
|
Thereafter
|
|
|
25,614
|
|
|
|
|
|
|
Total minimum rental payments
|
|
$
|
93,596
|
|
F-32 | ||
|
F-33 | ||
|
F-34 | ||
|
|
|
Shares
|
|
Weighted-
Average Grant Date Fair Value |
|
|
Non vested balance, beginning of period
|
|
219
|
|
$
|
12.00
|
|
Granted
|
|
356
|
|
|
18.32
|
|
Vested
|
|
(51)
|
|
|
12.00
|
|
Forfeited
|
|
|
|
|
|
|
Non vested balance, end of period
|
|
524
|
|
$
|
16.29
|
|
Available for grant
|
|
1,025
|
|
|
|
|
|
|
Period from January 1
through August 31, 2012 |
|
|
|
|
|
|
|||
|
|
Options
|
|
Weighted-Average
Exercise Price |
|
Weighted-Average
Remaining Contractual Term |
|
Aggregate
Intrinsic Value |
|
||
Outstanding-beginning of year
|
|
150,300
|
|
$
|
75.00
|
|
|
|
|
|
|
Granted
|
|
|
|
|
|
|
|
|
|
|
|
Exercised
|
|
|
|
|
|
|
|
|
|
|
|
Expired / canceled
|
|
(150,300)
|
|
|
(75.00)
|
|
|
|
|
|
|
Outstanding-end of year
|
|
|
|
$
|
|
|
|
|
$
|
|
|
Exercisable-end of year
|
|
|
|
$
|
|
|
|
|
$
|
|
|
|
|
Period from January 1
through August 31, 2012 |
|
|
|
|
|
|
|||
|
|
Nonvested
Stock |
|
Weighted-Average
Grant-Date Fair Value |
|
Weighted-Average
Remaining Contractual Term |
|
Aggregate
Intrinsic Value |
|
||
Nonvested-beginning of year
|
|
558,301
|
|
$
|
7.45
|
|
|
|
|
|
|
Granted
|
|
|
|
|
|
|
|
|
|
|
|
Vested
|
|
|
|
|
|
|
|
|
|
|
|
Expired / canceled
|
|
(558,301)
|
|
|
(7.45)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nonvested-end of year
|
|
|
|
$
|
|
|
|
|
$
|
|
|
F-35 | ||
|
|
|
Successor
|
|
Predecessor
|
|
|||||
|
|
|
|
|
Period from
|
|
Period from
|
|
||
|
|
|
|
|
September 1
|
|
January 1
|
|
||
|
|
Year Ended
|
|
through
|
|
through
|
|
|||
|
|
December 31,
|
|
December 31,
|
|
August 31,
|
|
|||
|
|
2013
|
|
|
2012
|
|
|
2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
U.S.Federal
|
|
$
|
|
|
$
|
|
|
$
|
|
|
U.S.State
|
|
|
(179)
|
|
|
|
|
|
|
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
U.S.Federal
|
|
|
(14)
|
|
|
(2,757)
|
|
|
|
|
U.S.State
|
|
|
193
|
|
|
|
|
|
|
|
Total
|
|
$
|
|
|
$
|
(2,757)
|
|
$
|
|
|
F-36 | ||
|
|
|
Successor
|
|
Predecessor
|
|
|||||
|
|
|
|
|
Period from
|
|
Period from
|
|
||
|
|
|
|
|
September 1
|
|
January 1
|
|
||
|
|
Year Ended
|
|
through
|
|
through
|
|
|||
|
|
December 31,
|
|
December 31,
|
|
August 31,
|
|
|||
|
|
2013
|
|
2012
|
|
2012
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
Federal statutory rate
|
|
|
(35.0)
|
%
|
|
(35.0)
|
%
|
|
(35.0)
|
%
|
State income taxes, net of federal benefit
|
|
|
0.1
|
%
|
|
|
|
|
|
|
Change in valuation allowance
|
|
|
21.7
|
%
|
|
(2.0)
|
%
|
|
(33.0)
|
|
Professional fees related to bankruptcy reorganization
|
|
|
|
|
|
8.0
|
%
|
|
17.0
|
%
|
Revenue from Wapiti Trust settlement
|
|
|
|
|
|
5.0
|
%
|
|
|
|
Cancellation of debt tax attribute reduction
|
|
|
|
|
|
|
|
|
51.0
|
%
|
Permanent Items
|
|
|
4.1
|
%
|
|
|
|
|
|
|
Provision to return adjustments
|
|
|
9.1
|
%
|
|
|
|
|
|
|
Actual income tax rate
|
|
|
|
%
|
|
(24.0)
|
%
|
|
|
%
|
|
|
2013
|
|
|
2012
|
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
Net operating loss
|
|
$
|
540,867
|
|
$
|
450,195
|
|
Capital loss carry forwards
|
|
|
26,141
|
|
|
26,141
|
|
Property and equipment
|
|
|
34,683
|
|
|
23,045
|
|
Investment in Piceance Energy
|
|
|
32,138
|
|
|
45,172
|
|
Derivative instruments
|
|
|
|
|
|
1,498
|
|
Accrued bonuses
|
|
|
|
|
|
|
|
Trust liabilitiy
|
|
|
1,327
|
|
|
|
|
Other
|
|
|
1,183
|
|
|
1,506
|
|
Total deferred tax assets
|
|
|
636,339
|
|
|
547,557
|
|
Valuation allowance
|
|
|
(633,954)
|
|
|
(544,442)
|
|
Net deferred tax assets
|
|
$
|
2,385
|
|
$
|
3,115
|
|
Deferred tax liabilities:
|
|
|
|
|
|
|
|
Property and equipment
|
|
$
|
5
|
|
$
|
|
|
Texadian Energy intangibles
|
|
|
2,380
|
|
|
3,083
|
|
Prepaid insurance, marketable securities and other
|
|
|
|
|
|
32
|
|
State liabilities
|
|
|
216
|
|
|
|
|
Total deferred tax liabilities
|
|
$
|
2,601
|
|
$
|
3,115
|
|
Total deferred tax liability, net
|
|
$
|
(216)
|
|
$
|
|
|
F-37 | ||
|
|
|
Successor
|
|
|
Predecessor
|
|
|||||
|
|
|
|
|
September 1
|
|
|
January 1
|
|
||
|
|
Year Ended
|
|
through
|
|
|
through
|
|
|||
|
|
December 31,
|
|
December 31,
|
|
|
August 31,
|
|
|||
|
|
2013
|
|
2012
|
|
|
2012
|
|
|||
Net loss attributable to common stockholders
|
|
$
|
(70,621)
|
|
$
|
(8,839)
|
|
|
$
|
(45,437)
|
|
Basic weighted-average common shares
outstanding |
|
|
19,740
|
|
|
15,734
|
|
|
|
28,841
|
|
Add: dilutive effects of stock options and
unvested stock grants (1) |
|
|
|
|
|
|
|
|
|
|
|
Diluted weighted-average common stock outstanding
|
|
|
19,740
|
|
|
15,734
|
|
|
|
28,841
|
|
Basic loss per common share attributable to
common stockholders: |
|
|
|
|
|
|
|
|
|
|
|
Net loss
(1)
|
|
$
|
(3.57)
|
|
$
|
(0.56)
|
|
|
$
|
(1.57)
|
|
Diluted loss per common share attributable to
common stockholders: |
|
|
|
|
|
|
|
|
|
|
|
Net loss
(1)
|
|
$
|
(3.57)
|
|
$
|
(0.56)
|
|
|
$
|
(1.57)
|
|
|
(1)
|
Entities with a net loss from continuing operations are prohibited from including potential common shares in the computation of diluted per share amounts. Therefore, we have utilized the basic weighted-average common shares outstanding to calculate both basic and diluted loss per share for all parties presented.
|
|
|
Successor
|
|
|
Predecessor
|
|
||
|
|
|
|
Period from
|
|
|
Period from
|
|
|
|
|
|
September 1
|
|
|
January 1
|
|
|
|
Year Ended
|
|
through
|
|
|
through
|
|
|
|
December 31,
|
|
December 31,
|
|
|
August 31,
|
|
|
|
2013
|
|
2012
|
|
|
2012
|
|
Stock issuable upon conversion of convertible notes
|
|
|
|
|
|
|
379
|
|
Stock options
|
|
|
|
|
|
|
150
|
|
Non-vested restricted stock
|
|
523
|
|
|
|
|
558
|
|
Total potentially dilutive securities
|
|
523
|
|
|
|
|
1,087
|
|
For the year ended December 31, 2013
|
|
Refining,
Distribution and Marketing |
|
Natural Gas
and Oil Operations |
|
Commodity
Marketing and Logistics |
|
Corporate and
Other |
|
Total
|
|
|||||
Sales and operating revenues
|
|
$
|
778,126
|
|
$
|
7,739
|
|
$
|
100,149
|
|
$
|
|
|
$
|
886,014
|
|
Depreciation, depletion, amortization
and accretion |
|
|
2,267
|
|
|
1,686
|
|
|
2,009
|
|
|
20
|
|
|
5,982
|
|
Operating income (loss)
|
|
|
(19,318)
|
|
|
246
|
|
|
9,126
|
|
|
(29,367)
|
|
|
(39,313)
|
|
Loss from unconsolidated affiliate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,941)
|
|
Interest expense and financing costs, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(19,471)
|
|
Other income (expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
808
|
|
Change in value of common stock warrants
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(10,114)
|
|
Gain on derivative instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
410
|
|
Loss before income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(70,621)
|
|
Income tax benefit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(70,621)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, including acquisitions
|
|
$
|
567,332
|
|
$
|
471
|
|
$
|
(1,300)
|
|
$
|
544
|
|
$
|
567,047
|
|
F-38 | ||
|
|
|
Natural Gas
and Oil Operations |
|
Commodity
Marketing and Logistics |
|
Corporate and
Other |
|
Total
|
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, including acquisitions
|
|
$
|
415
|
|
$
|
17,439
|
|
$
|
|
|
$
|
17,854
|
|
|
|
Refining,
Distribution and Marketing |
|
Natural Gas
and Oil Operations |
|
Commodity
Marketing and Logistics |
|
Corporate and
Other |
|
Total
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2013
|
|
$
|
655,712
|
|
$
|
109,316
|
|
$
|
52,048
|
|
$
|
10,009
|
|
$
|
827,085
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2012
|
|
$
|
|
|
$
|
116,034
|
|
$
|
62,754
|
|
$
|
10,794
|
|
$
|
189,582
|
|
F-39 | ||
|
F-40 | ||
|
F-41 | ||
|
|
|
|
August 31, 2012
|
|
|||||||||||
|
|
|
|
|
|
Plan of
|
|
|
|
Fresh Start
|
|
|
|
|
|
|
|
|
|
|
|
Reorganization
|
|
|
|
Reporting
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
Adjustments
|
|
|
|
Adjustments
|
|
|
|
Successor
|
|
|
|
(in thousands)
|
|
||||||||||||
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
1,954
|
|
$
|
74,167
|
(a)
|
|
$
|
|
|
|
$
|
4,882
|
|
|
|
|
|
|
|
(45,035)
|
(c)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(24,204)
|
(d)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,000)
|
(e)
|
|
|
|
|
|
|
|
|
Trust assets
|
|
|
|
|
|
3,446
|
(e)
|
|
|
|
|
|
|
3,446
|
|
Restricted cash
|
|
|
|
|
|
20,359
|
(d)
|
|
|
|
|
|
|
20,359
|
|
Trade accounts receivable, net
|
|
|
3,708
|
|
|
(1,727)
|
(a)
|
|
|
(1,981)
|
(g)
|
|
|
|
|
Prepaid assets
|
|
|
4,777
|
|
|
|
|
|
|
(4,777)
|
(g)
|
|
|
|
|
Prepaid reorganization costs
|
|
|
1,326
|
|
|
|
|
|
|
(1,326)
|
(g)
|
|
|
|
|
Total current assets
|
|
|
11,765
|
|
|
|
|
|
|
|
|
|
|
28,687
|
|
Property and equipment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unproved
|
|
|
84
|
|
|
|
|
|
|
(84)
|
(g)
|
|
|
|
|
Proved
|
|
|
759,755
|
|
|
(740,392)
|
(a)
|
|
|
(14,776)
|
(g)
|
|
|
4,587
|
|
Land
|
|
|
4,000
|
|
|
(4,000)
|
(a)
|
|
|
|
|
|
|
|
|
Other
|
|
|
73,021
|
|
|
(47,493)
|
(a)
|
|
|
(21,289)
|
(g)
|
|
|
4,239
|
|
Total property and equipment
|
|
|
836,860
|
|
|
|
|
|
|
|
|
|
|
8,826
|
|
Less accumulated depreciation and depletion
|
|
|
(642,172)
|
|
|
607,603
|
(a)
|
|
|
34,569
|
(g)
|
|
|
|
|
Property and equipment, net
|
|
|
194,688
|
|
|
|
|
|
|
|
|
|
|
8,826
|
|
Long-term assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investments in unconsolidated affiliates
|
|
|
3,629
|
|
|
105,344
|
(a)
|
|
|
(3,629)
|
(g)
|
|
|
105,344
|
|
Other long-term assets
|
|
|
307
|
|
|
|
|
|
|
(253)
|
(g)
|
|
|
54
|
|
Total long-term assets
|
|
|
3,936
|
|
|
|
|
|
|
|
|
|
|
105,398
|
|
Total assets
|
|
$
|
210,389
|
|
|
|
|
|
|
|
|
|
$
|
142,911
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities not subject to compromise
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debtor in possession financing
|
|
$
|
56,535
|
|
|
(56,535)
|
(c)
|
|
|
|
|
|
$
|
|
|
Accounts payable and other accrued liabilities
|
|
|
4,897
|
|
|
|
|
|
|
|
|
|
|
4,897
|
|
Other accrued liabilities
|
|
|
9,224
|
|
|
(2,685)
|
(b)
|
|
|
|
|
|
|
2,640
|
|
|
|
|
|
|
|
(1,500)
|
(c)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,845)
|
(d)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,446
|
(e)
|
|
|
|
|
|
|
|
|
Accrued reorganization and trustee expense
|
|
|
70,656
|
|
|
|
|
|
|
|
|
|
|
7,537
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities subject to compromise
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3
3
/
4
% Senior notes
|
|
|
115,000
|
|
|
(115,000)
|
(b)
|
|
|
|
|
|
|
|
|
7% Senior convertible notes
|
|
|
150,000
|
|
|
(150,000)
|
(b)
|
|
|
|
|
|
|
|
|
Accounts payable and other accrued liabilities
|
|
|
17,203
|
|
|
(2,560)
|
(a)
|
|
|
(1,981)
|
(g)
|
|
|
12,336
|
|
|
|
|
|
|
|
(3,526)
|
(d)
|
|
|
3,200
|
(g)
|
|
|
|
|
Total current liabilities
|
|
|
352,859
|
|
|
|
|
|
|
|
|
|
|
19,873
|
|
Long-term liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities not subject to compromise
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long term debt
|
|
|
|
|
|
6,335
|
(c)
|
|
|
|
|
|
|
6,335
|
|
Derivative liabilities
|
|
|
|
|
|
6,665
|
(c)
|
|
|
|
|
|
|
6,665
|
|
Asset retirement obligations
|
|
|
4,414
|
|
|
(3,938)
|
(a)
|
|
|
|
|
|
|
476
|
|
Total liabilities
|
|
|
357,273
|
|
|
|
|
|
|
|
|
|
|
33,349
|
|
Stockholders’ equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock
|
|
|
288
|
|
|
1,457
|
(b)
|
|
|
(288)
|
(f)
|
|
|
1,477
|
|
|
|
|
|
|
|
20
|
(d)
|
|
|
|
|
|
|
|
|
Additional paid-in capital
|
|
|
1,643,285
|
|
|
100,084
|
(b)
|
|
|
288
|
(f)
|
|
|
108,085
|
|
|
|
|
|
|
|
1,318
|
(d)
|
|
|
(1,636,890)
|
(h)
|
|
|
|
|
Retained earnings (accumulated deficit)
|
|
|
(1,790,457)
|
|
|
166,144
|
(b)
|
|
|
(14,765)
|
(g)
|
|
|
|
|
|
|
|
|
|
|
2,188
|
(d)
|
|
|
1,636,890
|
(h)
|
|
|
|
|
Total stockholders’ equity (deficit)
|
|
|
(146,884)
|
|
|
|
|
|
|
|
|
|
|
109,562
|
|
Total liabilities and equity (deficit)
|
|
$
|
210,389
|
|
|
|
|
|
|
|
|
|
$
|
142,911
|
|
F-42 | ||
|
|
(a)
|
Reflects the contribution of certain of our oil and gas assets and related prepaid expenses and asset retirement obligations to Piceance Energy in exchange for cash and a 33.34% interest in Piceance Energy.
|
|
|
|
|
(b)
|
Reflects the extinguishment of secured debt in exchange for common stock of the Successor. On the Emergence Date, we issued
14,573,608
shares of our common stock and warrants to acquire
959,213
shares of our common stock to the holders of our secured debt or their affiliates. We estimated the fair value of our common stock to be $
7.00
per share on the Emergence Date. Accordingly, we recorded a gain on the settlement of secured debt within Reorganization items of approximately $166.1 million on the Predecessor’s consolidated statement of operations in the period from January 1, 2012 through August 31, 2012.
|
|
|
|
|
(c)
|
Reflects the Successor drawing $
13
million under the Loan Agreement (see Note 10 - Debt) to repay amounts outstanding under the DIP Credit Facility with those proceeds and cash from contribution of assets to Piceance Energy.
|
|
|
|
|
(d)
|
Reflects the settlement of other claims with common stock of Successor and cash. On the Emergence Date, we issued
191,973
shares of our common stock to various creditors. We estimated the fair value of our common stock to be $
7.00
per share on the Emergence Date. Accordingly, we recorded a gain on settlement of liabilities within Reorganization items of approximately $2.2 million on the Predecessor’s consolidated statement of operations in the period from January 1, 2012 through August 31, 2012.
|
|
|
|
|
(e)
|
Reflects the funding of the Recovery Trusts (see
Note 13 - Commitments and Contingencies
).
|
|
|
|
|
(f)
|
Reflects the cancellation of Predecessor common stock.
|
|
|
|
|
(g)
|
Reflects adjustments to remaining assets due to fresh-start reporting. On the Emergence Date, we adjusted the carrying value of our remaining assets to their estimated fair values. As a result of these adjustments, we recorded a loss for changes in asset fair values due to fresh-start reporting adjustments within Reorganization items of approximately $
14.8
million on the Predecessor’s consolidated statement of operations in the period from January 1, 2012 through August 31, 2012.
|
|
|
|
|
(h)
|
Reflects the elimination of
Predecessor’s
accumulated deficit.
|
|
|
Successor
|
|
|
Predecessor
|
|
|||||
|
|
December 31,
2013 |
|
December 31,
2012 |
|
|
August 31,
2012 |
|
|||
Company:
|
|
|
|
|
|
|
|
|
|
|
|
Unproved properties
|
|
$
|
|
|
$
|
|
|
|
$
|
84
|
|
Proved properties
|
|
|
4,949
|
|
|
4,804
|
|
|
|
759,755
|
|
|
|
|
4,949
|
|
|
4,804
|
|
|
|
759,839
|
|
Accumulated depreciation and depletion
|
|
|
(1,868)
|
|
|
(337)
|
|
|
|
(642,172)
|
|
|
|
$
|
3,081
|
|
$
|
4,467
|
|
|
$
|
117,667
|
|
Company’s Share of Piceance Energy:
|
|
|
|
|
|
|
|
|
|
|
|
Unproved properties
|
|
$
|
15,763
|
|
$
|
16,180
|
|
|
|
|
|
Proved properties
|
|
|
168,378
|
|
|
134,638
|
|
|
|
|
|
|
|
|
184,141
|
|
|
150,818
|
|
|
|
|
|
Accumulated depreciation and depletion
|
|
|
(38,452)
|
|
|
(2,808)
|
|
|
|
|
|
|
|
$
|
145,689
|
|
$
|
148,010
|
|
|
|
|
|
F-43 | ||
|
(1)
|
The capitalized cost amounts presented are as of August 31, 2012 for the Predecessor and exclude adjustments resulting from the plan or reorganization and fresh-start reporting (see Note 19 - Reorganization Under Chapter 11, Fresh-Start Reporting and the Effects of the Plan).
|
|
|
Successor
|
|
|
Predecessor
|
|
|||||
|
|
Year Ended
December 31, 2013 |
|
Period from
September 1 through December 31, 2012 |
|
|
Period from
January 1 through August 31, 2012 |
|
|||
Company:
|
|
|
|
|
|
|
|
|
|
|
|
Development costs incurred on proved undeveloped
reserves |
|
$
|
|
|
$
|
|
|
|
$
|
1,613
|
|
Development costsother
|
|
|
142
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
142
|
|
$
|
|
|
|
$
|
1,613
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Company’s Share of Piceance Energy:
|
|
|
|
|
|
|
|
|
|
|
|
Unproved properties acquisition costs
|
|
$
|
|
|
$
|
206
|
|
|
|
|
|
Proved properties acquisition costs (1)
|
|
|
|
|
|
32,519
|
|
|
|
|
|
Development costsother
|
|
|
6,380
|
|
|
291
|
|
|
|
|
|
Total
|
|
$
|
6,380
|
|
$
|
33,016
|
|
|
|
|
|
(1)
|
Amount represents our share of proved oil and natural gas property acquired at inception of the formation of Piceance Energy, of which $
24.2
million relates to oil and natural gas properties purchased from Delta contemplated as part the emergence from bankruptcy and $
8.3
million relates oil and natural gas properties purchased from Laramie.
|
F-44 | ||
|
|
|
Successor
|
|
|
Predecessor
|
|
|||||
|
|
Year Ended
December 31, 2013 |
|
September 1
through December 31, 2012 |
|
|
January 1
through August 31, 2012 |
|
|||
Company:
|
|
|
|
|
|
|
|
|
|
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas revenues
|
|
$
|
7,739
|
|
$
|
2,144
|
|
|
$
|
23,079
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
Production costs
|
|
|
5,696
|
|
|
1,688
|
|
|
|
16,980
|
|
Depletion and amortization
|
|
|
1,593
|
|
|
370
|
|
|
|
16,041
|
|
Exploration
|
|
|
|
|
|
|
|
|
|
2
|
|
Abandoned and impaired properties
|
|
|
|
|
|
|
|
|
|
151,347
|
|
Results of operations of oil and gas producing activities
|
|
$
|
450
|
|
$
|
86
|
|
|
$
|
(161,291)
|
|
Company’s share of Piceance Energy:
|
|
|
|
|
|
|
|
|
|
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas revenues
|
|
$
|
20,364
|
|
$
|
6,464
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
Production costs
|
|
|
9,885
|
|
|
3,033
|
|
|
|
|
|
Depletion and amortization
|
|
|
8,855
|
|
|
2,808
|
|
|
|
|
|
Results of operations of oil and gas producing activities
|
|
$
|
1,624
|
|
$
|
623
|
|
|
|
|
|
Total Company and Piceance Energy income from
operations of oil and gas producing activities |
|
$
|
2,074
|
|
$
|
709
|
|
|
|
|
|
F-45 | ||
|
|
|
Gas
|
|
Oil
|
|
NGLS
|
|
Total
|
|
|
|
(MMcf)
|
|
(MBbl)
|
|
(MBb1)
|
|
(MMcfe)
(5)
|
|
Company:
|
|
|
|
|
|
|
|
|
|
Estimated Proved Reserves: Balance at January 1, 2012
(Predecessor) (1) |
|
87,209
|
|
494
|
|
|
|
90,173
|
|
Revisions of quantity estimate
|
|
|
|
85
|
|
|
|
512
|
|
Sale/disposition of properties
(2)
|
|
(82,357)
|
|
(235)
|
|
|
|
(83,770)
|
|
Production
|
|
(4,852)
|
|
(67)
|
|
|
|
(5,256)
|
|
Estimated Proved Reserves: Balance at August 31, 2012
(Successor) |
|
|
|
277
|
|
|
|
1,659
|
|
Revisions of quantity estimate
|
|
456
|
|
31
|
|
|
|
643
|
|
Production
|
|
(10)
|
|
(22)
|
|
|
|
(139)
|
|
Estimated Proved Reserves: Balance at December 31, 2012
(Successor) |
|
446
|
|
286
|
|
|
|
2,163
|
|
Revisions of quantity estimate
|
|
460
|
|
16
|
|
|
|
557
|
|
Extensions and discoveries
|
|
9
|
|
3
|
|
|
|
25
|
|
Production
|
|
(253)
|
|
(69)
|
|
|
|
(667)
|
|
Estimated Proved Reserves: Balance at December 31, 2013
(Successor) |
|
662
|
|
236
|
|
|
|
2,078
|
|
Company’s Share of Piceance Energy:
|
|
|
|
|
|
|
|
|
|
Estimated Proved Reserves: Balance at September 1, 2012
|
|
|
|
|
|
|
|
|
|
Transfer from investees
(3)
|
|
83,915
|
|
560
|
|
4,228
|
|
112,639
|
|
Revisions of quantity estimate
|
|
8,053
|
|
41
|
|
387
|
|
10,621
|
|
Extensions and discoveries
|
|
32,073
|
|
236
|
|
1,778
|
|
44,151
|
|
Production
|
|
(1,391)
|
|
(6)
|
|
(48)
|
|
(1,711)
|
|
Estimated Proved Reserves: Balance at December 31, 2012
|
|
122,650
|
|
831
|
|
6,345
|
|
165,700
|
|
Revisions of quantity estimate
|
|
72,436
|
|
174
|
|
2,818
|
|
90,387
|
|
Extensions and discoveries
|
|
3,599
|
|
(374)
|
|
(1,334)
|
|
(6,643)
|
|
Production
|
|
(12,088)
|
|
(47)
|
|
(428)
|
|
(14,935)
|
|
Estimated Proved Reserves: Balance at December 31, 2013
|
|
186,597
|
|
584
|
|
7,401
|
|
234,509
|
|
Total Estimated Proved Reserves: Balance at December 31, 2013
|
|
187,259
|
|
820
|
|
7,401
|
|
236,587
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves
|
|
|
|
|
|
|
|
|
|
December 31, 2012
|
|
158
|
|
286
|
|
|
|
1,875
|
|
December 31, 2012Company Share of Piceance Energy
|
|
48,680
|
|
237
|
|
2,253
|
|
63,617
|
|
Total December 31, 2012
|
|
48,838
|
|
523
|
|
2,253
|
|
65,492
|
|
Proved undeveloped reserves
|
|
|
|
|
|
|
|
|
|
December 31, 2012
|
|
288
|
|
|
|
|
|
288
|
|
December 31, 2012Company Share of Piceance Energy
|
|
73,970
|
|
594
|
|
4,092
|
|
102,083
|
|
Total December 31, 2012
|
|
74,258
|
|
594
|
|
4,092
|
|
102,371
|
|
Proved developed reserves
|
|
|
|
|
|
|
|
|
|
December 31, 2013
|
|
662
|
|
236
|
|
|
|
2,078
|
|
December 31, 2013Company Share of Piceance Energy
|
|
45,072
|
|
165
|
|
1,627
|
|
55,829
|
|
Total December 31, 2013
|
|
45,734
|
|
401
|
|
1,627
|
|
57,907
|
|
Proved undeveloped reserves
|
|
|
|
|
|
|
|
|
|
December 31, 2013
|
|
|
|
|
|
|
|
|
|
December 31, 2013Company Share of Piceance Energy
|
|
141,525
|
|
419
|
|
5,774
|
|
178,680
|
|
Total December 31, 2013
|
|
141,525
|
|
419
|
|
5,774
|
|
178,680
|
|
|
|
CIG per Mbtu
|
|
WTI per Bbl
|
|
||
|
|
||||||
Base pricing, before adjustments for contractual
differentials: (4) |
|
|
|
|
|
|
|
August 31, 2012
|
|
$
|
2.75
|
|
$
|
90.85
|
|
December 31, 2012
|
|
$
|
2.56
|
|
$
|
91.21
|
|
December 31, 2012 Piceance
|
|
$
|
2.56
|
|
$
|
91.21
|
|
December 31, 2013
|
|
$
|
3.53
|
|
$
|
96.91
|
|
December 31, 2013 Piceance
|
|
$
|
3.53
|
|
$
|
96.91
|
|
(1)
|
At January 1, 2012, gas is based on
70,982
MMcf of natural gas and
4,057
MBbl of natural gas liquids, with liquids converted to gas using a ratio of 4 Mcf to 1 barrel.
|
(2)
|
On August 31, 2012, substantially all of the reserves of the company were transferred to Piceance Energy in exchange for
a
33.34
% equity
ownership interest (See Note 3 - Investment in Piceance Energy).
|
(3)
|
On August 31, 2012, certain reserves held by Delta Petroleum and by Laramie were transferred to Piceance Energy in exchange for a
33.34
% and a
66.66
% equity ownership interest, respectively
(See Note 3 - Investment in Piceance Energy).
|
(4)
|
Proved reserves are required to be calculated based on the 12-month, first day of the month historical average price in accordance with SEC rules. The prices shown above are base index prices to which adjustments are made for contractual deducts and other factors.
|
(5)
|
MMcfe is based on a ratio of 6 Mcf to 1 barrel.
|
F-46 | ||
|
|
|
Successor
|
|
|
Predecessor
|
|
|||||
|
|
December 31,
|
|
|
August 31,
|
|
|||||
|
|
2013
|
|
2012
|
|
|
2012
|
|
|||
|
|
(in thousands)
|
|
|
(in thousands)
|
|
|||||
Company:
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
$
|
26,861
|
|
$
|
30,444
|
|
|
$
|
28,691
|
|
Future costs:
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
21,999
|
|
|
20,596
|
|
|
|
19,973
|
|
Development and abandonment
|
|
|
319
|
|
|
319
|
|
|
|
319
|
|
Income taxes
1
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
4,543
|
|
|
9,529
|
|
|
|
8,399
|
|
10% discount factor
|
|
|
(1,006)
|
|
|
(1,519)
|
|
|
|
(1,176)
|
|
Standardized measure of discounted future net cash
flows |
|
$
|
3,537
|
|
$
|
8,010
|
|
|
$
|
7,223
|
|
Company’s Share of Piceance Energy:
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
$
|
984,205
|
|
$
|
568,706
|
|
|
|
|
|
Future costs:
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
430,506
|
|
|
199,277
|
|
|
|
|
|
Development and abandonment
|
|
|
234,905
|
|
|
154,054
|
|
|
|
|
|
Income taxes
1
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
318,794
|
|
|
215,375
|
|
|
|
|
|
10% discount factor
|
|
|
(229,469)
|
|
|
(143,416)
|
|
|
|
|
|
Standardized measure of discounted future net
cash flows |
|
$
|
89,325
|
|
$
|
71,959
|
|
|
|
|
|
Total Company and Company share of equity
investee in the standardized measure of discounted future net revenues |
|
$
|
92,862
|
|
$
|
79,969
|
|
|
|
|
|
|
|
Successor
|
|
|||||||
|
|
December 31,
|
|
Company Share
of Piceance Energy December 31, |
|
Total
|
|
|||
|
|
2013
|
|
2013
|
|
2013
|
|
|||
Beginning of the year
|
|
|
|
|
|
|
|
|
|
|
Beginning of the period
|
|
$
|
8,010
|
|
$
|
71,959
|
|
$
|
79,969
|
|
Sales of oil and gas production during the period, net of
production costs |
|
|
(2,044)
|
|
|
(10,478)
|
|
|
(12,522)
|
|
Net change in prices and production costs
|
|
|
(3,833)
|
|
|
(2,588)
|
|
|
(6,421)
|
|
Changes in estimated future development costs
|
|
|
|
|
|
8,831
|
|
|
8,831
|
|
Extensions, discoveries and improved recovery
|
|
|
147
|
|
|
15,471
|
|
|
15,618
|
|
Revisions of previous quantity estimates, estimated timing of
development and other |
|
|
395
|
|
|
(4,948)
|
|
|
(4,553)
|
|
Previously estimated development and abandonment costs
incurred during the period |
|
|
|
|
|
3,142
|
|
|
3,142
|
|
Other
|
|
|
61
|
|
|
740
|
|
|
801
|
|
Accretion of discount
|
|
|
801
|
|
|
7,196
|
|
|
7,997
|
|
End of period
|
|
$
|
3,537
|
|
$
|
89,325
|
|
$
|
92,862
|
|
|
|
Successor
|
|
|
Predecessor
|
|
||||||||
|
|
Period from
September 1, through December 31, |
|
Company Share
of Piceance Energy September 1, through December 31, |
|
Total
|
|
|
January 1,
through August 31, |
|
||||
|
|
2012
|
|
2012
|
|
2012
|
|
|
2012
|
|
||||
Beginning of the year
|
|
|
|
|
|
|
|
|
|
|
|
$
|
129,695
|
|
Beginning of the period
|
|
$
|
7,223
|
|
$
|
|
|
$
|
7,223
|
|
|
|
|
|
Transfer from investees
|
|
|
|
|
|
55,253
|
|
|
55,253
|
|
|
|
|
|
Sales of oil and gas production during the period,
net of production costs |
|
|
(456)
|
|
|
(3,639)
|
|
|
(4,095)
|
|
|
|
(5,954)
|
|
Net change in prices and production costs
|
|
|
(667)
|
|
|
(139)
|
|
|
(806)
|
|
|
|
378
|
|
Changes in estimated future development costs
|
|
|
|
|
|
5
|
|
|
5
|
|
|
|
|
|
Extensions, discoveries and improved recovery
|
|
|
763
|
|
|
569
|
|
|
1,332
|
|
|
|
|
|
Revisions of previous quantity estimates, estimated
timing of development and other |
|
|
648
|
|
|
13,708
|
|
|
14,356
|
|
|
|
(7,439)
|
|
Sales/disposition of reserves in place
|
|
|
|
|
|
|
|
|
|
|
|
|
(118,104)
|
|
Other
|
|
|
258
|
|
|
4,360
|
|
|
4,618
|
|
|
|
|
|
Accretion of discount
|
|
|
241
|
|
|
1,842
|
|
|
2,083
|
|
|
|
8,647
|
|
End of period
|
|
$
|
8,010
|
|
$
|
71,959
|
|
$
|
79,969
|
|
|
$
|
7,223
|
|
F-47 | ||
|
|
PAR PETROLEUM CORPORATION
|
|
|
|
|
|
By:
|
/s/ William Monteleone.
|
|
|
William Monteleone, Chief Executive Officer
|
|
|
|
|
By:
|
/s/ Christopher Micklas
|
|
|
Christopher Micklas, Chief Financial Officer
|
Signature and Title
|
|
Date
|
|
|
|
/s/ William Monteleone
|
|
March 31, 2014
|
William Monteleone, Chief Executive Officer (Principal Executive Officer)
|
|
|
|
|
|
/s/ Christopher Micklas
|
|
March 31, 2014
|
Christopher Micklas, Chief Financial Officer (Principal Financial and Accounting Officer)
|
|
|
|
|
|
/s/ Jacob Mercer
|
|
March 31, 2014
|
Jacob Mercer, Director
|
|
|
|
|
|
/s/ Benjamin Lurie
|
|
March 31, 2014
|
Benjamin Lurie, Director
|
|
|
|
|
|
/s/ Michael Keener
|
|
March 31, 2014
|
Michael Keener, Director
|
|
|
|
|
|
/s/ L. Melvin Cooper
|
|
March 31, 2014
|
L. Melvin Cooper, Director
|
|
|
|
Exhibit 21.1
Subsidiaries of the Registrant
Name | Jurisdiction |
Par Piceance Energy Equity, LLC | Delaware |
Texadian Energy, Inc. | Delaware |
Hawaii Pacific Energy, LLC | Delaware |
EWI, LLC | Delaware |
Par Washington, LLC | Delaware |
Par Utah, LLC | Delaware |
Par New Mexico, LLC | Delaware |
HEWW Equipment, LLC | Delaware |
HIE Retail, LLC | Hawaii |
Hawaii Independent Energy LLC | Hawaii |
Smiley’s Super Service, Inc. | Hawaii |
Texadian Energy Canada Limited | Alberta, Canada |
Piceance Energy, LLC (33.34% interest) | Delaware |
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in Registration Statement No. 333-192519 on Form S-3 and Registration Statement No. 333-185612 on Form S-8 of our report dated March 31, 2014, relating to the consolidated financial statements of Par Petroleum Corporation as of and for the year ended December 31, 2013, appearing in this Annual Report on Form 10-K of Par Petroleum Corporation for the year ended December 31, 2013.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
March 31, 2014
Exhibit 23.2
CONSENT OF INDEPENDENT REGISTERED ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the registration statements on Form S-8 (File No. 333-185612) and on Form S-3 (File No. 333-192519) of Par Petroleum Corporation of our report dated March 27, 2013 and updated for Note 14 on March 31, 2014, with respect to the consolidated balance sheet of Par Petroleum Corporation and subsidiaries as of December 31, 2012 and the related consolidated statements of operations and comprehensive loss, changes in equity, and cash flows for the period from September 1, 2012 through December 31, 2012 and of our report dated February 28, 2014, with respect to the balance sheet of Piceance Energy, LLC as of December 31, 2013 and the related statements of operations, members’ equity, and cash flows for the year then ended, appearing in the Annual Report on Form 10-K of Par Petroleum Corporation for the fiscal year ended December 31, 2013.
EKS&H LLLP
Denver, Colorado
March 31, 2014
Exhibit 23.3
Consent of Independent Registered Public Accounting Firm
To the Board of Directors
Par Petroleum Corporation, Successor to Delta Petroleum Corporation
We consent to the incorporation by reference in the registration statement on Form S-8 (No. 333-185612) and on Form S-3 (File No. 333-192519)) of Par Petroleum Corporation (formerly Delta Petroleum Corporation) and subsidiaries (the Predecessor) of our report dated March 27, 2013, with respect to the consolidated statements of operations (Predecessor), changes in equity (Predecessor), and cash flows (Predecessor) for the period January 1, 2012 through August 31, 2012, which report appears in the December 31, 2013 annual report on Form 10-K of Par Petroleum Corporation.
Our report over the consolidated financial statements contains an explanatory paragraph that states that the Predecessor filed a petition for reorganization under Chapter 11 of the United States Bankruptcy Code on December 16, 2011. The Predecessor’s plan of reorganization became effective and the Company emerged from bankruptcy protection on August 31, 2012. In connection with its emergence from bankruptcy, the Company adopted the guidance for fresh start accounting in conformity with FASB ASC Topic 852, Reorganizations, effective as of August 31, 2012. Accordingly, the Predecessor’s consolidated financial statements prior to August 31, 2012 are not comparable to its consolidated financial statements for periods after August 31, 2012.
/s/ KPMG LLP
KPMG LLP
Denver, Colorado
March 31, 2014
Exhibit 23.4
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
We hereby consent to the inclusion in this Annual Report on Form 10-K of Par Petroleum Corporation for the year ended December 31, 2013, of our report dated March 17, 2014, with respect to estimates of reserves and future net revenue of Par Petroleum Corporation, as of December 31, 2013, and to all references to our firm included in this Annual Report.
NETHERLAND, SEWELL & ASSOCIATES, INC. | |||
By: | /s/ C.H. (Scott) Rees III | ||
C.H. (Scott) Rees III | |||
Chairman and Chief Executive Officer | |||
Dallas, Texas
March 31, 2014
Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document. |
Exhibit 31.1
CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER PURSUANT TO RULE 13a-14(a)/15d-14(a) PROMULGATED UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED
I, William Monteleone, certify that:
1. I have reviewed this annual report on Form 10-K of Par Petroleum Corporation;
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and have: |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Date: March 31, 2014
/s/ William Monteleone
William Monteleone
Chief Executive Officer
Exhibit 31.2
CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER PURSUANT TO RULE 13a-14(a) PROMULGATED UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED
I, Christopher Micklas, certify that:
1. I have reviewed this annual report on Form 10-K of Par Petroleum Corporation;
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and have: |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Date: March 31, 2014
/s/ Christopher Micklas
Christopher Micklas
Chief Financial Officer
Exhibit 32.1
CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER
PURSUANT TO 18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 906
OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Par Petroleum Corporation (the “Company”) on Form 10-K for the year ended December 31, 2013 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, William Monteleone, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:
1. | The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and |
2. | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
/s/ William Monteleone
William Monteleone
Chief Executive Officer
March 31, 2014
Exhibit 32.2
CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER
PURSUANT TO 18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 906
OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Par Petroleum Corporation (the “Company”) on Form 10-K for the year ended December 31, 2013 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Christopher Micklas, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:
1. | The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and |
2. | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
/s/ Christopher Micklas
Christopher Micklas
Chief Financial Officer
March 31, 2014
March 17, 2014
Mr. Chris Micklas
Par Petroleum Corporation
800 Gessner Road, Suite 875
Houston, Texas 77024
Dear Mr. Micklas:
In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2013, to the Par Petroleum Corporation (Par) interest in certain oil and gas properties located in California, Colorado, and New Mexico. We completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by Par. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Par's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.
We estimate the net reserves and future net revenue to the Par interest in these properties, as of December 31, 2013, to be:
Net Reserves | Future Net Revenue (M$) | |||||||||||||||||||
Oil | NGL | Gas | Present Worth | |||||||||||||||||
Category | (MBBL) | (MBBL) | (MMCF) | Total | at 10% | |||||||||||||||
Proved Developed Producing | 362.3 | 1,138.8 | 33,357.3 | 78,084.3 | 47,349.2 | |||||||||||||||
Proved Developed Non-Producing | 39.1 | 488.6 | 12,376.9 | 29,364.7 | 10,372.1 | |||||||||||||||
Proved Undeveloped | 418.6 | 5,773.9 | 141,524.8 | 215,888.3 | 35,140.6 | |||||||||||||||
Total Proved | 820.1 | 7,401.3 | 187,259.0 | 323,337.3 | 92,861.9 |
Totals may not add because of rounding.
The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.
The estimates shown in this report are for proved reserves. As requested, probable and possible reserves that exist for these properties have not been included. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.
Gross revenue is Par's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for Par's share of production taxes, ad valorem taxes, capital costs, abandonment costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.
Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2013. For oil and NGL volumes, the average West Texas Intermediate spot price of $96.91 per barrel is adjusted by lease for quality, transportation fees, and regional price differentials. For gas volumes, the average CIG Rocky Mountains spot price of $3.527 per MMBTU is used for the Colorado properties and the average Henry Hub spot price of $3.670 per MMBTU is used for the New Mexico properties. These average regional spot prices are adjusted by lease for energy content and regional price differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $89.70 per barrel of oil, $32.05 per barrel of NGL, and $3.740 per MCF of gas. By area, these average adjusted prices are $101.08 per barrel of oil for the California properties; $85.33 per barrel of oil, $32.05 per barrel of NGL, and $3.740 per MCF of gas for the Colorado properties; and $91.30 per barrel of oil and $4.576 per MCF of gas for the New Mexico properties.
Operating costs used in this report are based on operating expense records of Par. These costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Operating costs have been divided into per-well costs and per-unit-of-production costs. Since all properties are nonoperated, headquarters general and administrative overhead expenses of Par are not included. Operating costs are not escalated for inflation.
Capital costs used in this report were provided by Par and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. As requested, our estimates do not include any salvage value for the lease and well equipment or the cost of abandoning the properties, except for the saltwater disposal wells and the California properties. For the saltwater disposal wells, abandonment costs used in this report are the operator's estimates of the costs to abandon the wells, net of any salvage value. For the California properties, abandonment costs used in this report are Par's estimates of the costs to abandon the wells, net of any salvage value. Capital costs and abandonment costs are not escalated for inflation.
For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.
We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the Par interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Par receiving its net revenue interest share of estimated future gross production.
The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.
For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. A substantial portion of these reserves are for behind-pipe zones, non-producing zones, undeveloped locations, and producing wells that lack sufficient production history upon which performance-related estimates of reserves can be based; such reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.
The data used in our estimates were obtained from Par, other interest owners, various operators of the properties, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.
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/ Dan Paul Smith | /s/ John G. Hattner | ||
By: | By: | ||
Dan Paul Smith, P.E. 49093 | John G. Hattner, P.G. 559 | ||
Senior Vice President | Senior Vice President | ||
Date Signed: March 17, 2014 | Date Signed: March 17, 2014 |
BWJ: JSB
Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document. |
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations.
(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.
(2) Analogous reservoir . Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:
(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. |
Instruction to paragraph (a)(2) : Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.
(3) Bitumen . Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.
(4) Condensate . Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
(5) Deterministic estimate . The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.
(6) Developed oil and gas reserves . Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
(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. |
Supplemental definitions from the 2007 Petroleum Resources Management System:
Developed Producing Reserves – Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.
Developed Non-Producing Reserves – Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well. |
Definitions - Page 1 of 7 |
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:
(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. |
(8) Development project . A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
(9) Development well . A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
(10) Economically producible . The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.
(11) Estimated ultimate recovery (EUR) . Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.
(12) Exploration costs . Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:
(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. |
(13) Exploratory well . An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.
(14) Extension well . An extension well is a well drilled to extend the limits of a known reservoir.
Definitions - Page 2 of 7 |
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(15) Field . An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.
(16) Oil and gas producing activities.
(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. |
Instruction 1 to paragraph (a)(16)(i) : The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:
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. |
Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.
(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. |
(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
(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. |
Definitions - Page 3 of 7 |
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(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. |
(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
(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. |
(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.
(20) Production costs.
(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. |
Definitions - Page 4 of 7 |
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(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. |
(21) Proved area. The part of a property to which proved reserves have been specifically attributed.
(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(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. |
(23) Proved properties. Properties with proved reserves.
(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.
Definitions - Page 5 of 7 |
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
Note to paragraph (a)(26) : Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas: | ||
932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year: | ||
a. | Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B) | |
b. | Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7). | |
The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes. | ||
932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B: | ||
a. | Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end. | |
b. | Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs. | |
c. | Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves. | |
d. | Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows. | |
e. | Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves. | |
f. | Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount. |
(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Definitions - Page 6 of 7 |
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.
(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.
(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.
(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
(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. |
From the SEC's Compliance and Disclosure Interpretations (October 26, 2009): | ||
Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule. | ||
Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following: | ||
Ÿ | The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities); | |
Ÿ | The company's historical record at completing development of comparable long-term projects; | |
Ÿ | The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities; | |
Ÿ | The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and | |
Ÿ | The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority). |
(iii) | Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such 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. |
(32) Unproved properties. Properties with no proved reserves.
Definitions - Page 7 of 7 |