Item 1. Financial Statements
CONSTELLATION ENERGY PARTNERS LLC and SUBSIDIARIES
Condensed Consolidated Balance Sheets
|
|
|
|
|
|
|
|
|
|
|
June 30, 2013
|
|
|
December 31, 2012
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
(In 000s except unit data)
|
|
ASSETS
|
|
|
|
|
|
|
|
|
Current assets
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
9,541
|
|
|
$
|
1,959
|
|
Accounts receivable
|
|
|
4,442
|
|
|
|
5,615
|
|
Prepaid expenses
|
|
|
1,386
|
|
|
|
1,309
|
|
Risk management assets (see Note 4)
|
|
|
13,912
|
|
|
|
17,965
|
|
Current assets from discontinued operations
|
|
|
|
|
|
|
1,886
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
29,281
|
|
|
|
28,734
|
|
Oil and natural gas properties (See Note 6)
|
|
|
|
|
|
|
|
|
Oil and natural gas properties, equipment and facilities
|
|
|
599,336
|
|
|
|
594,020
|
|
Material and supplies
|
|
|
1,282
|
|
|
|
771
|
|
Less accumulated depreciation, depletion, amortization, and impairments
|
|
|
(483,726
|
)
|
|
|
(474,669
|
)
|
|
|
|
|
|
|
|
|
|
Net oil and natural gas properties
|
|
|
116,892
|
|
|
|
120,122
|
|
Other assets
|
|
|
|
|
|
|
|
|
Debt issue costs (net of accumulated amortization of $8,953 and $7,775, respectively)
|
|
|
830
|
|
|
|
1,168
|
|
Risk management assets (see Note 4)
|
|
|
7,032
|
|
|
|
7,431
|
|
Other non-current assets
|
|
|
4,232
|
|
|
|
3,194
|
|
Long-term assets from discontinued operations
|
|
|
|
|
|
|
67,373
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
158,267
|
|
|
$
|
228,022
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND MEMBERS EQUITY
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
581
|
|
|
$
|
480
|
|
Accrued liabilities
|
|
|
7,829
|
|
|
|
7,174
|
|
Royalty payable
|
|
|
1,373
|
|
|
|
1,418
|
|
Risk management liabilities (see Note 4)
|
|
|
|
|
|
|
523
|
|
Debt
|
|
|
|
|
|
|
50,000
|
|
Current liabilities from discontinued operations
|
|
|
|
|
|
|
1,578
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
9,783
|
|
|
|
61,173
|
|
Other liabilities
|
|
|
|
|
|
|
|
|
Asset retirement obligation
|
|
|
8,036
|
|
|
|
7,665
|
|
Risk management liabilities (see Note 4)
|
|
|
|
|
|
|
637
|
|
Other non-current liabilities
|
|
|
1,978
|
|
|
|
589
|
|
Debt
|
|
|
34,000
|
|
|
|
34,000
|
|
Other long-term liabilities from discontinued operations
|
|
|
|
|
|
|
7,692
|
|
|
|
|
|
|
|
|
|
|
Total other liabilities
|
|
|
44,014
|
|
|
|
50,583
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
53,797
|
|
|
|
111,756
|
|
Commitments and contingencies (See Note 8)
|
|
|
|
|
|
|
|
|
Members equity
|
|
|
|
|
|
|
|
|
Class A units, 484,097 and 483,418 units authorized, issued and outstanding, respectively
|
|
|
2,090
|
|
|
|
2,326
|
|
Class B units, 24,124,378 and 24,124,378 units authorized, respectively, and 23,720,732 and 23,687,507 issued and outstanding,
respectively
|
|
|
102,380
|
|
|
|
113,940
|
|
|
|
|
|
|
|
|
|
|
Total members equity
|
|
|
104,470
|
|
|
|
116,266
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and members equity
|
|
$
|
158,267
|
|
|
$
|
228,022
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to condensed consolidated financial statements.
3
CONSTELLATION ENERGY PARTNERS LLC and SUBSIDIARIES
Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
|
Six Months Ended
June 30,
|
|
|
|
2013
|
|
|
2012
|
|
|
2013
|
|
|
2012
|
|
|
|
(In 000s except unit data)
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales
|
|
$
|
10,025
|
|
|
$
|
2,741
|
|
|
$
|
11,417
|
|
|
$
|
21,345
|
|
Oil and liquids sales
|
|
|
5,363
|
|
|
|
6,458
|
|
|
|
9,071
|
|
|
|
8,468
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
(see Note 4)
|
|
|
15,388
|
|
|
|
9,199
|
|
|
|
20,488
|
|
|
|
29,813
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
3,905
|
|
|
|
4,687
|
|
|
|
8,141
|
|
|
|
9,858
|
|
Cost of sales
|
|
|
379
|
|
|
|
251
|
|
|
|
799
|
|
|
|
636
|
|
Production taxes
|
|
|
622
|
|
|
|
365
|
|
|
|
1,109
|
|
|
|
767
|
|
General and administrative
|
|
|
3,737
|
|
|
|
3,705
|
|
|
|
8,141
|
|
|
|
7,541
|
|
Gain on sale of assets
|
|
|
(17
|
)
|
|
|
(4
|
)
|
|
|
(23
|
)
|
|
|
|
|
Depreciation, depletion, and amortization
|
|
|
4,767
|
|
|
|
2,318
|
|
|
|
9,565
|
|
|
|
4,705
|
|
Asset impairments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
107
|
|
Accretion expense
|
|
|
123
|
|
|
|
115
|
|
|
|
246
|
|
|
|
229
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
13,516
|
|
|
|
11,437
|
|
|
|
27,978
|
|
|
|
23,843
|
|
Other expenses (income)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
864
|
|
|
|
1,437
|
|
|
|
2,216
|
|
|
|
3,056
|
|
Other expense (income)
|
|
|
(104
|
)
|
|
|
4
|
|
|
|
(172
|
)
|
|
|
(93
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expenses
|
|
|
760
|
|
|
|
1,441
|
|
|
|
2,044
|
|
|
|
2,963
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
14,276
|
|
|
|
12,878
|
|
|
|
30,022
|
|
|
|
26,806
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations
|
|
$
|
1,112
|
|
|
$
|
(3,679
|
)
|
|
$
|
(9,534
|
)
|
|
$
|
3,007
|
|
Discontinued operations
|
|
$
|
|
|
|
$
|
(1,331
|
)
|
|
$
|
(2,686
|
)
|
|
$
|
(2,132
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
1,112
|
|
|
$
|
(5,010
|
)
|
|
$
|
(12,220
|
)
|
|
$
|
875
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in fair value of commodity hedges
|
|
|
|
|
|
|
65
|
|
|
|
|
|
|
|
88
|
|
Cash settlement of commodity hedges
|
|
|
|
|
|
|
(1,927
|
)
|
|
|
|
|
|
|
(2,645
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive loss
|
|
|
|
|
|
|
(1,862
|
)
|
|
|
|
|
|
|
(2,557
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss)
|
|
$
|
1,112
|
|
|
$
|
(6,872
|
)
|
|
$
|
(12,220
|
)
|
|
$
|
(1,682
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per unit (see Note 2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) from continuing operations per unitBasic
|
|
$
|
0.05
|
|
|
$
|
(0.15
|
)
|
|
$
|
(0.40
|
)
|
|
$
|
0.12
|
|
Earnings (loss) from discontinued operations per unitBasic
|
|
$
|
|
|
|
$
|
(0.06
|
)
|
|
$
|
(0.11
|
)
|
|
$
|
(0.08
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings (loss) per unitBasic
|
|
$
|
0.05
|
|
|
$
|
(0.21
|
)
|
|
$
|
(0.51
|
)
|
|
$
|
0.04
|
|
Units outstandingBasic
|
|
|
23,829,650
|
|
|
|
24,159,301
|
|
|
|
23,799,631
|
|
|
|
24,173,012
|
|
Earnings (loss) from continuing operations per unitDiluted
|
|
$
|
0.05
|
|
|
$
|
(0.15
|
)
|
|
$
|
(0.40
|
)
|
|
$
|
0.12
|
|
Earnings (loss) from discontinued operations per unitDiluted
|
|
$
|
|
|
|
$
|
(0.06
|
)
|
|
$
|
(0.11
|
)
|
|
$
|
(0.08
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings (loss) per unitDiluted
|
|
$
|
0.05
|
|
|
$
|
(0.21
|
)
|
|
$
|
(0.51
|
)
|
|
$
|
0.04
|
|
Units outstandingDiluted
|
|
|
24,205,102
|
|
|
|
24,159,301
|
|
|
|
23,799,631
|
|
|
|
24,232,246
|
|
Distributions declared and paid per unit
|
|
$
|
0.00
|
|
|
$
|
0.00
|
|
|
$
|
0.00
|
|
|
$
|
0.00
|
|
See accompanying notes to condensed consolidated financial statements.
4
CONSTELLATION ENERGY PARTNERS LLC and SUBSIDIARIES
Condensed Consolidated Statements of Cash Flows
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Six months ended
June
30,
|
|
|
|
2013
|
|
|
2012
|
|
|
|
(In 000s)
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(12,220
|
)
|
|
$
|
875
|
|
Adjustments to reconcile net income (loss) to cash provided by operating activities
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
9,565
|
|
|
|
4,705
|
|
Asset impairments (see Note 6)
|
|
|
|
|
|
|
107
|
|
Amortization of debt issuance costs
|
|
|
1,178
|
|
|
|
646
|
|
Accretion expense
|
|
|
246
|
|
|
|
229
|
|
Equity (earnings) losses in affiliate
|
|
|
(172
|
)
|
|
|
(108
|
)
|
Gain from disposition of property and equipment
|
|
|
(23
|
)
|
|
|
|
|
Bad debt expense
|
|
|
15
|
|
|
|
26
|
|
(Gain) Loss from mark-to-market activities
|
|
|
3,290
|
|
|
|
(2,310
|
)
|
Unit-based compensation programs
|
|
|
609
|
|
|
|
665
|
|
Discontinued operations
|
|
|
2,686
|
|
|
|
2,132
|
|
Changes in Assets and Liabilities:
|
|
|
|
|
|
|
|
|
(Increase) decrease in accounts receivable
|
|
|
1,160
|
|
|
|
1,055
|
|
(Increase) decrease in prepaid expenses
|
|
|
(77
|
)
|
|
|
(48
|
)
|
(Increase) decrease in other assets
|
|
|
(1,149
|
)
|
|
|
(599
|
)
|
Increase (decrease) in accounts payable
|
|
|
101
|
|
|
|
87
|
|
Increase (decrease) in accrued liabilities
|
|
|
(1,391
|
)
|
|
|
(3,541
|
)
|
Increase (decrease) in royalty payable
|
|
|
(45
|
)
|
|
|
(197
|
)
|
Increase (decrease) in other liabilities
|
|
|
1,139
|
|
|
|
354
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by continuing operations
|
|
|
4,912
|
|
|
|
4,078
|
|
Net cash provided by discontinued operations
|
|
|
1,062
|
|
|
|
1,291
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
5,974
|
|
|
|
5,369
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
Cash paid for acquisitions, net of cash acquired
|
|
|
(130
|
)
|
|
|
|
|
Development of oil and natural gas properties
|
|
|
(6,319
|
)
|
|
|
(6,807
|
)
|
Proceeds from sale of assets
|
|
|
58,987
|
|
|
|
1,505
|
|
Distributions from equity affiliate
|
|
|
95
|
|
|
|
100
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) continuing operations
|
|
|
52,633
|
|
|
|
(5,202
|
)
|
Net cash used in discontinued operations
|
|
|
|
|
|
|
(62
|
)
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) investing activities
|
|
|
52,633
|
|
|
|
(5,264
|
)
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
Members distributions
|
|
|
|
|
|
|
|
|
Proceeds from issuance of debt
|
|
|
194
|
|
|
|
|
|
Repayment of debt
|
|
|
(50,194
|
)
|
|
|
(10,000
|
)
|
Units tendered by employees for tax withholdings
|
|
|
(185
|
)
|
|
|
(183
|
)
|
Debt issue costs
|
|
|
(840
|
)
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
|
Net cash used in continuing operations
|
|
|
(51,025
|
)
|
|
|
(10,186
|
)
|
Net cash used in discontinued operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in financing activities
|
|
|
(51,025
|
)
|
|
|
(10,186
|
)
|
|
|
|
|
|
|
|
|
|
Net (decrease) increase in cash and cash equivalents
|
|
|
7,582
|
|
|
|
(10,081
|
)
|
Cash and cash equivalents, beginning of period
|
|
|
1,959
|
|
|
|
17,176
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
9,541
|
|
|
$
|
7,095
|
|
|
|
|
|
|
|
|
|
|
Supplemental disclosures of cash flow information:
|
|
|
|
|
|
|
|
|
Change in accrued capital expenditures
|
|
$
|
(351
|
)
|
|
$
|
745
|
|
Cash received during the period for interest
|
|
$
|
|
|
|
$
|
1
|
|
Cash paid during the period for interest
|
|
$
|
(1,012
|
)
|
|
$
|
(1,974
|
)
|
See accompanying notes to condensed consolidated financial statements.
5
CONSTELLATION ENERGY PARTNERS LLC and SUBSIDIARIES
Condensed Consolidated Statements of Changes in Members Equity
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Class A
|
|
|
Class B
|
|
|
Accumulated
Other
Comprehensive
|
|
|
Total
Members
|
|
|
|
Units
|
|
|
Amount
|
|
|
Units
|
|
|
Amount
|
|
|
Income (Loss)
|
|
|
Equity
|
|
|
|
( In 000s, except unit data)
|
|
Balance, December 31, 2012
|
|
|
483,418
|
|
|
$
|
2,326
|
|
|
|
23,687,507
|
|
|
$
|
113,940
|
|
|
$
|
|
|
|
$
|
116,266
|
|
Distributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Units tendered by employees for tax withholding
|
|
|
(2,853
|
)
|
|
|
(4
|
)
|
|
|
(139,810
|
)
|
|
|
(181
|
)
|
|
|
|
|
|
|
(185
|
)
|
Unit-based compensation programs
|
|
|
3,532
|
|
|
|
12
|
|
|
|
173,035
|
|
|
|
597
|
|
|
|
|
|
|
|
609
|
|
Net income (loss)
|
|
|
|
|
|
|
(244
|
)
|
|
|
|
|
|
|
(11,976
|
)
|
|
|
|
|
|
|
(12,220
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, June 30, 2013
|
|
|
484,097
|
|
|
$
|
2,090
|
|
|
|
23,720,732
|
|
|
$
|
102,380
|
|
|
$
|
|
|
|
$
|
104,470
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to condensed consolidated financial statements.
6
CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. ORGANIZATION AND BASIS OF PRESENTATION
The consolidated financial statements as of, and for the period ended, June 30, 2013, are unaudited, but in the
opinion of management include all adjustments (consisting only of normal recurring adjustments) necessary for a fair statement of the results for the interim periods. Certain information and note disclosures normally included in annual financial
statements prepared in accordance with U.S. generally accepted accounting principles (U.S. GAAP) have been condensed or omitted under Securities and Exchange Commission (SEC) rules and regulations. The results reported in
these unaudited consolidated financial statements should not necessarily be taken as indicative of results that may be expected for the entire year.
The financial information included herein should be read in conjunction with the financial statements and notes in the Companys Annual Report on Form 10-K for the year ended December 31, 2012,
which was filed on March 11, 2013. Certain amounts in the consolidated financial statements and notes thereto have been reclassified to conform to the 2013 financial statement presentation and to reflect our discontinued operations.
Constellation Energy Partners LLC (CEP, we, us, our or the Company) was
organized as a limited liability company on February 7, 2005, under the laws of the State of Delaware. We completed our initial public offering on November 20, 2006, and currently trade on the NYSE MKT LLC (NYSE MKT) under the
symbol CEP. Through subsidiaries, both PostRock Energy Corporation (NASDAQ: PSTR) (PostRock) and Exelon Corporation (NYSE: EXC) (Exelon), own a portion of our outstanding units. As of June 30, 2013,
Constellation Energy Partners Management, LLC (CEPM), a subsidiary of PostRock, owned all of our Class A units and 5,918,894 of our Class B common units, and Constellation Energy Partners Holdings, LLC (CEPH), a
subsidiary of Exelon, owned all of our Class C management incentive interests and all of our Class D interests.
We are
currently focused on the development and acquisition of oil and natural gas properties in the Cherokee Basin in Kansas and Oklahoma, the Woodford Shale in Oklahoma, and the Central Kansas Uplift in Kansas.
Accounting policies used by us conform to U.S. GAAP. The accompanying financial statements include the accounts of us and our
wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. We operate our oil and natural gas properties as one business segment: the exploration, development and production of oil and
natural gas. Our management evaluates performance based on one business segment as there are not different economic environments within the operation of our oil and natural gas properties.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Our significant accounting policies are consistent with those discussed in our Annual Report on Form 10-K for the year
ended December 31, 2012.
Earnings per Unit
Basic earnings per unit (EPU) are computed by dividing net income attributable to unitholders by the weighted average number of units outstanding during each period. At June 30, 2013, we
had 484,097 Class A units and 23,720,732 Class B common units outstanding. Of the Class B common units, 375,452 units are restricted unvested common units granted and outstanding.
The following table presents earnings per common unit amounts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(Loss)
|
|
|
Weighted Average
Units Outstanding
|
|
|
Per Unit
Amount
|
|
|
|
(In 000s except unit data)
|
|
For the three months ended June 30, 2013
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic EPU:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations allocable to unitholders
|
|
$
|
1,112
|
|
|
|
23,829,650
|
|
|
$
|
0.05
|
|
Income (loss) from discontinued operations allocable to unitholders
|
|
$
|
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) allocable to unitholders
|
|
$
|
1,112
|
|
|
|
23,829,650
|
|
|
$
|
0.05
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(Loss)
|
|
|
Weighted Average
Units Outstanding
|
|
|
Per Unit
Amount
|
|
|
|
(In 000s except unit data)
|
|
Diluted EPU:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations allocable to unitholders
|
|
$
|
1,112
|
|
|
|
24,205,102
|
|
|
$
|
0.05
|
|
Income (loss) from discontinued operations allocable to unitholders
|
|
$
|
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) allocable to unitholders
|
|
$
|
1,112
|
|
|
|
24,205,102
|
|
|
$
|
0.05
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(Loss)
|
|
|
Weighted Average
Units Outstanding
|
|
|
Per Unit
Amount
|
|
|
|
(In 000s except unit data)
|
|
For the six months ended June 30, 2013
|
|
|
|
|
|
Basic EPU:
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations allocable to unitholders
|
|
$
|
(9,534
|
)
|
|
|
23,799,631
|
|
|
$
|
(0.40
|
)
|
Income (loss) from discontinued operations allocable to unitholders
|
|
$
|
(2,686
|
)
|
|
|
|
|
|
$
|
(0.11
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) allocable to unitholders
|
|
$
|
(12,220
|
)
|
|
|
23,799,631
|
|
|
$
|
(0.51
|
)
|
Diluted EPU:
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations allocable to unitholders
|
|
$
|
(9,534
|
)
|
|
|
23,799,631
|
|
|
$
|
(0.40
|
)
|
Income (loss) from discontinued operations allocable to unitholders
|
|
$
|
(2,686
|
)
|
|
|
|
|
|
$
|
(0.11
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) allocable to unitholders
|
|
$
|
(12,220
|
)
|
|
|
23,799,631
|
|
|
$
|
(0.51
|
)
|
|
|
|
|
|
|
Income
(Loss)
|
|
|
Weighted Average
Units Outstanding
|
|
|
Per Unit
Amount
|
|
|
|
(In 000s except unit data)
|
|
For the three months ended June 30, 2012
|
|
|
|
|
|
|
|
|
Basic EPU:
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations allocable to unitholders
|
|
$
|
(3,679
|
)
|
|
|
24,159,301
|
|
|
$
|
(0.15
|
)
|
Income (loss) from discontinued operations allocable to unitholders
|
|
$
|
(1,331
|
)
|
|
|
|
|
|
$
|
(0.06
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) allocable to unitholders
|
|
$
|
(5,010
|
)
|
|
|
24,159,301
|
|
|
$
|
(0.21
|
)
|
Diluted EPU:
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations allocable to unitholders
|
|
$
|
(3,679
|
)
|
|
|
24,159,301
|
|
|
$
|
(0.15
|
)
|
Income (loss) from discontinued operations allocable to unitholders
|
|
$
|
(1,331
|
)
|
|
|
|
|
|
$
|
(0.06
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) allocable to unitholders
|
|
$
|
(5,010
|
)
|
|
|
24,159,301
|
|
|
$
|
(0.21
|
)
|
|
|
|
|
|
|
Income
(Loss)
|
|
|
Weighted Average
Units Outstanding
|
|
|
Per Unit
Amount
|
|
|
|
(In 000s except unit data)
|
|
For the six months ended June 30, 2012
|
|
|
|
|
|
|
|
|
Basic EPU:
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations allocable to unitholders
|
|
$
|
3,007
|
|
|
|
24,173,012
|
|
|
$
|
0.12
|
|
Income (loss) from discontinued operations allocable to unitholders
|
|
$
|
(2,132
|
)
|
|
|
|
|
|
$
|
(0.08
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) allocable to unitholders
|
|
$
|
875
|
|
|
|
24,173,012
|
|
|
$
|
0.04
|
|
Diluted EPU:
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations allocable to unitholders
|
|
$
|
3,007
|
|
|
|
24,232,246
|
|
|
$
|
0.12
|
|
Income (loss) from discontinued operations allocable to unitholders
|
|
$
|
(2,132
|
)
|
|
|
|
|
|
$
|
(0.08
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) allocable to unitholders
|
|
$
|
875
|
|
|
|
24,232,246
|
|
|
$
|
0.04
|
|
8
Cash
All highly liquid investments with original maturities of three months or less are considered cash. Checks-in-transit are included in our consolidated balance sheets as accounts payable or as a reduction
of cash, depending on the type of bank account the checks were drawn on. Our checks-in-transit reported in accounts payable were none at June 30, 2013, and $0.5 million at December 31, 2012.
We have established an escrow account for $0.6 million related to a vendor dispute, which is included in other non-current assets in our
consolidated balance sheets at June 30, 2013, and December 31, 2012. This amount will remain in the escrow account until the dispute has been resolved. We also have an escrow account for approximately $1.2 million related to the sale of
our Robinsons Bend Field assets in the Black Warrior Basin of Alabama, which is included in other non-current assets in our consolidated balance sheets at June 30, 2013. These funds will be held in escrow for a period up to twenty-four
months pending certain closing conditions.
3. RECENT ACCOUNTING PRONOUNCEMENTS AND ACCOUNTING CHANGES
In December 2011, the Financial Accounting Standards Board (FASB) issued ASU No. 2011-11,
Disclosures about Offsetting Assets and Liabilities,
which requires additional disclosures for financial and derivative instruments that are either (1) offset in accordance with either Accounting Standards Codification (ASC)
210-20-45 or ASC 815-10-45 or (2) subject to an enforceable master netting arrangement or similar agreement, regardless of whether they are offset in accordance with either ASC 210-20-45 or ASC 815-10-45. The guidance was effective beginning on
or after January 1, 2013, and primarily impacts the disclosures associated with our commodity and interest rate derivatives. Implementation of this guidance did not have any material impact on our consolidated financial position, results of
operations or cash flows.
4. DERIVATIVE AND FINANCIAL INSTRUMENTS
Mark-to-Market Activities
As of June 30, 2013, we have hedged a portion of our expected natural gas and oil sales from currently producing wells through December 2016. All of our derivatives were accounted for as
mark-to-market activities as of June 30, 2013.
For the six months ended June 30, 2013 and 2012, we recognized
mark-to-market losses of approximately $6.9 million and mark-to-market gains of approximately $1.7 million, respectively, in connection with our commodity derivatives. For the six months ended June 30, 2013 and 2012, we recognized a
mark-to-market gain of approximately $3.6 million and $0.6 million, respectively, in connection with our interest rate derivatives. At June 30, 2013 and December 31, 2012, the fair value of our derivatives accounted for as mark-to-market
activities amounted to a net asset of approximately $20.9 million and $24.2 million, respectively.
Fair Value Measurements
We measure fair value of our financial and non-financial assets and liabilities on a recurring basis. Accounting
standards define fair value, establish a framework for measuring fair value and require certain disclosures about fair value measurements for assets and liabilities measured on a recurring basis. All of our derivative instruments are recorded at
fair value in our financial statements. Fair value is the exit price that we would receive to sell an asset or pay to transfer a liability in an orderly transaction between market participants at the measurement date.
The following hierarchy prioritizes the inputs used to measure fair value. The three levels of the fair value hierarchy are as follows:
|
|
|
Level 1 Quoted prices available in active markets for identical assets or liabilities as of the reporting date.
|
|
|
|
Level 2 Pricing inputs other than quoted prices in active markets included in Level 1 which are either directly or indirectly observable as of
the reporting date. Level 2 consists primarily of non-exchange traded commodity and interest rate derivatives.
|
|
|
|
Level 3 Pricing inputs include significant inputs that are generally less observable from objective sources.
|
9
We classify assets and liabilities within the fair value hierarchy based on the lowest level
of input that is significant to the fair value measurement of each individual asset and liability taken as a whole. The income valuation approach, which involves discounting estimated cash flows, is primarily used to determine recurring fair value
measurements of our derivative instruments classified as Level 2. Our commodity derivatives are valued using the terms of the individual derivative contracts with our counterparties, expected future levels of oil and natural gas prices, and an
appropriate discount rate. Our interest rate derivatives are valued using the terms of the individual derivative contracts with our counterparties, expected future levels of the LIBOR interest rates, and an appropriate discount rate. We prioritize
the use of the highest level inputs available in determining fair value such that fair value measurements are determined using the highest and best use as determined by market participants and the assumptions that they would use in determining fair
value. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the classification of assets and liabilities within the fair value hierarchy. Because of the long-term nature of certain
assets and liabilities measured at fair value as well as differences in the availability of market prices and market liquidity over their terms, inputs for some assets and liabilities may fall into any one of the three levels in the fair value
hierarchy. While we are required to classify these assets and liabilities in the lowest level in the hierarchy for which inputs are significant to the fair value measurement, a portion of that measurement may be determined using inputs from a higher
level in the hierarchy.
The following tables set forth by level within the fair value hierarchy our assets and liabilities
that were measured at fair value on a recurring basis as of June 30, 2013 and December 31, 2012.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity and Interest
Rate Derivatives
|
|
|
|
|
|
Netting and
Cash
Collateral*
|
|
|
Total Net Fair
Value
|
|
At June 30, 2013
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
|
|
|
(In 000s)
|
|
Risk management assets
|
|
$
|
|
|
|
$
|
22,517
|
|
|
$
|
|
|
|
$
|
(1,573
|
)
|
|
$
|
20,944
|
|
Risk management liabilities
|
|
$
|
|
|
|
$
|
(1,573
|
)
|
|
$
|
|
|
|
$
|
1,573
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net assets and liabilities
|
|
$
|
|
|
|
$
|
20,944
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
20,944
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity and Interest
Rate Derivatives
|
|
|
|
|
|
Netting and
Cash
Collateral*
|
|
|
Total Net Fair
Value
|
|
At December 31, 2012
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
|
|
|
(In 000s)
|
|
Risk management assets
|
|
$
|
|
|
|
$
|
31,030
|
|
|
$
|
|
|
|
$
|
(5,634
|
)
|
|
$
|
25,396
|
|
Risk management liabilities
|
|
$
|
|
|
|
$
|
(6,794
|
)
|
|
$
|
|
|
|
$
|
5,634
|
|
|
$
|
(1,160
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net assets and liabilities
|
|
$
|
|
|
|
$
|
24,236
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
24,236
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
We currently use our reserve-based credit facility to provide credit support for our derivative transactions and therefore we do not post cash collateral with our
counterparties. Amounts shown represent the impact of netting assets and liabilities with our counterparties for which the right of offset exists.
|
Risk management assets and liabilities in the table above represent the current fair value of all open derivative positions. We classify all of our derivative instruments as Risk management
assets or Risk management liabilities in our Consolidated Balance Sheets.
We use observable market data or
information derived from observable market data in order to determine the fair value amounts presented above. We currently use our reserve-based credit facility to provide credit support for our derivative transactions. As a result, we do not post
cash collateral with our counterparties, and have minimal non-performance credit risk on our liabilities with counterparties. We utilize observable market data for credit default swaps to assess the impact of non-performance credit risk when
evaluating our net assets from counterparties. At June 30, 2013, the impact of non-performance credit risk on the valuation of our net assets from counterparties was $0.1 million, of which $0.1 million was reflected as a decrease to our
non-cash mark-to-market gain and none was reflected as a reduction to our accumulated other comprehensive income. At June 30, 2012, the impact of non-performance credit risk on the valuation of our net assets from counterparties was $0.5
million, of which $0.4 million was reflected as a decrease to our non-cash mark-to-market gain and $0.1 million was reflected in our accumulated other comprehensive loss.
Fair Value of Financial Instruments
As of June 30, 2013, we
have various commodity swaps for 15,316,767 MMbtu of natural gas production through December 2016, various basis swaps for 6,941,187 MMbtu of natural gas production in the Cherokee Basin through December 2014, and various commodity swaps for 335,651
Bbls of oil production through December 2016. We had no interest rate swaps at June 30, 2013.
Under the terms of our
reserve-based credit facility, we have agreed to hedge at least 100% of our reasonably estimated projected natural gas production for 2015 and 50% of our reasonably estimated projected natural gas production for 2016. All of the required 2015
hedges are in place, and we have agreed to enter into the remaining 2016 hedges on or before December 31, 2013. In the event that the 2016 hedges are not in place by December 31, 2013, our borrowing base will automatically be reduced
by the shortfall of actual hedges as compared to 50% of the reasonably estimated projected natural gas production, not to exceed an amount equal to $3.0 million times the calculated percentage of hedging shortfall. We expect to enter into the
2016 hedges prior to December 31, 2013.
10
The following represents the fair value for our risk management assets and liabilities, as
of June 30, 2013, and December 31, 2012, and the amount of gains and losses recognized at June 30, 2013 and 2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
Location of Asset/
(Liability) on Balance Sheet
|
|
Fair Value of Asset/
(Liability) on Balance Sheet
(in 000s)
|
|
Derivative Type
|
|
|
June 30, 2013
|
|
|
December 31, 2012
|
|
Commodity-MTM
|
|
Risk management assets-current
|
|
$
|
15,134
|
|
|
$
|
19,005
|
|
Commodity-MTM
|
|
Risk management assets-non-current
|
|
|
7,383
|
|
|
|
12,025
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gross assets
|
|
|
22,517
|
|
|
|
31,030
|
|
Commodity-MTM
|
|
Risk management assets-current
|
|
|
(1,222
|
)
|
|
|
(1,040
|
)
|
Commodity-MTM
|
|
Risk management assets-non-current
|
|
|
(351
|
)
|
|
|
(946
|
)
|
Commodity-MTM
|
|
Risk management liabilities-current
|
|
|
(0
|
)
|
|
|
(523
|
)
|
Commodity-MTM
|
|
Risk management liabilities-non-current
|
|
|
(0
|
)
|
|
|
(637
|
)
|
Interest Rate-MTM
|
|
Risk management assets-non-current
|
|
|
(0
|
)
|
|
|
(3,648
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gross liabilities
|
|
|
(1,573
|
)
|
|
|
(6,794
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net assets and liabilities
|
|
$
|
20,944
|
|
|
$
|
24,236
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of Gain / (Loss)
in Income
(in 000s)
|
|
Derivative Type
|
|
Location of Gain /(Loss)
in Income
|
|
Quarter Ended
June 30, 2013
|
|
|
Quarter Ended
June 30, 2012
|
|
Commodity-MTM-Unrealized
|
|
Natural gas sales
|
|
$
|
1,352
|
|
|
$
|
(8,455
|
)
|
Commodity-MTM-Unrealized
|
|
Oil and liquids sales
|
|
|
994
|
|
|
|
3,558
|
|
Commodity-MTM-Realized
|
|
Natural gas sales
|
|
|
2,730
|
|
|
|
7,307
|
|
Commodity-MTM-Realized
|
|
Oil and liquids sales
|
|
|
346
|
|
|
|
34
|
|
Interest Rate-MTM-Unrealized
|
|
Interest expense
|
|
|
984
|
|
|
|
513
|
|
Interest Rate-MTM-Realized
|
|
Interest expense
|
|
|
(1,003
|
)
|
|
|
(793
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
5,403
|
|
|
$
|
2,164
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of Gain / (Loss)
in Income
(in 000s)
|
|
Derivative Type
|
|
Location of Gain / (Loss)
in Income
|
|
Six Months Ended
June 30, 2013
|
|
|
Six Months Ended
June 30, 2012
|
|
Commodity-MTM-Unrealized
|
|
Natural gas sales
|
|
$
|
(7,129
|
)
|
|
$
|
(583
|
)
|
Commodity-MTM-Unrealized
|
|
Oil and liquids sales
|
|
|
190
|
|
|
|
2,288
|
|
Commodity-MTM-Realized
|
|
Natural gas sales
|
|
|
7,274
|
|
|
|
13,266
|
|
Commodity-MTM-Realized
|
|
Oil and liquids sales
|
|
|
507
|
|
|
|
123
|
|
Interest Rate-MTM-Unrealized
|
|
Interest expense
|
|
|
3,648
|
|
|
|
605
|
|
Interest Rate-MTM-Realized
|
|
Interest expense
|
|
|
(3,713
|
)
|
|
|
(1,285
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
777
|
|
|
$
|
14,414
|
|
|
|
|
|
|
|
|
|
|
|
|
11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Location of Gain/(Loss)
for Effective and
Ineffective
Portion of Derivative
in
Income
|
|
Amount of Gain/(Loss) Reclassified
from AOCI into Income -
Effective
|
|
Derivative Type
|
|
|
Quarter Ended
June 30,
2013
|
|
|
Quarter Ended
June 30,
2012
|
|
Commodity-Cash Flow
|
|
Natural gas sales
|
|
$
|
|
|
|
$
|
1,927
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
|
|
|
$
|
1,927
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Location of Gain/(Loss)
for Effective and
Ineffective
Portion of Derivative
in
Income
|
|
Amount of Gain/(Loss) Reclassified
from
AOCI into Income - Effective
|
|
Derivative Type
|
|
|
Six
Months Ended
June 30,
2013
|
|
|
Six
Months Ended
June 30,
2012
|
|
Commodity-Cash Flow
|
|
Natural gas sales
|
|
$
|
|
|
|
$
|
2,645
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
|
|
|
$
|
2,645
|
|
|
|
|
|
|
|
|
|
|
|
|
At June 30, 2013, the carrying values of our cash, accounts receivable, other current assets and
current liabilities on the Consolidated Balance Sheets approximate fair value because of their short-term nature.
We believe
the carrying value of long-term debt for our reserve-based credit facility approximates its fair value because the interest rates on the debt approximate market interest rates for debt with similar terms, which is a Level 2 measurement in the fair
value hierarchy and represents the amount at which the instrument could be valued in an exchange during a current transaction between willing parties. Our reserve-based credit facility is discussed in Note 5.
Hedge Liquidation, Repositioning and Novation
In the first quarter of 2013, we liquidated or repositioned certain of our hedges. In connection with the sale of our Robinsons Bend Field assets in the Black Warrior Basin of Alabama, we liquidated
395,218 MMbtu of NYMEX swaps in 2013 and 1,634,530 MMbtu of NYMEX swaps in 2014 at a cost of $0.3 million. In addition, we reduced our outstanding NYMEX swap positions in 2013 by 1,041,814 MMbtu by executing offsetting trades with our counterparties
at a fixed price of $3.662. These transactions ensure that our outstanding derivative positions in future periods are lower than our expected future natural gas production in those periods.
In March 2013, we reduced our outstanding interest rate swaps that fix our LIBOR rate through 2014 to $30 million, which increased our
interest rate swap settlements by $2.1 million. This position was closed in May 2013 resulting in an offsetting non-cash gain in our mark-to-market interest swap activities. We also amended a 2014 to 2015 oil trade with one of our hedge
counterparties to lower the stated swap price from $98.10 to $93.50, on a total of 58,157 barrels of oil. We received proceeds of approximately $0.2 million upon execution of the amendment. The proceeds were used for working capital purposes.
5. DEBT
Reserve-Based Credit Facility
In May 2013, we amended our existing reserve-based credit facility. This amendment increased our borrowing capacity, extended the maturity date and changed the lenders participating in the facility.
At June 30, 2013, we had a $350.0 million reserve-based credit facility with Societe Generale as administrative and
collateral agent and a syndicate of lenders. The reserve-based credit facility had a borrowing base of $55.0 million and matures on May 30, 2017. At June 30, 2013, we had $34.0 million in borrowings outstanding, which is reflected as a
non-current liability on our balance sheet. Borrowings under the reserve-based credit facility are secured by various mortgages of oil and natural gas properties that we and certain of our subsidiaries own as well as various security and pledge
agreements among us and certain of our subsidiaries and the administrative agent. The lenders and their percentage commitments in the reserve-based credit facility are Societe Generale (36.36%), OneWest Bank, FSB (36.36%), and BOKF NA, dba Bank of
Oklahoma (27.28%).
12
At our election, interest for borrowings are determined by reference to (i) the London
interbank rate, or LIBOR, plus an applicable margin between 2.50% and 3.50% per annum based on utilization or (ii) a domestic bank rate (ABR) plus an applicable margin between 1.50% and 2.50% per annum based on utilization
plus (iii) a commitment fee of 0.50% per annum based on the unutilized borrowing base. Interest on the borrowings for ABR loans and the commitment fee are generally payable quarterly. Interest on the borrowings for LIBOR loans are
generally payable at the applicable maturity date.
The reserve-based credit facility contains various covenants that limit,
among other things, our ability and certain of our subsidiaries ability to incur certain indebtedness, grant certain liens, merge or consolidate, sell all or substantially all of our assets, make certain loans, acquisitions, capital
expenditures and investments, and pay distributions. The reserve-based credit facility limits our ability to pay distributions to unitholders and permits us to hedge our projected monthly production and the interest rate on our borrowings.
Debt Issue Costs
During the six months ended June 30, 2013, we accelerated the amortization of approximately $0.7 million in debt issue costs as a result of amendments to and refinancing of our reserve-based credit
facility. Accelerated amortization of the debt issue costs was required as the syndicate of lenders participating in the reserve-based credit facility changed. As of June 30, 2013, our unamortized debt issue costs were approximately $0.8
million. These costs are being amortized over the life of our reserve-based credit facility.
Funds Available for Borrowing
As of June 30, 2013 and 2012, we had $34.0 million and $88.4 million, respectively, in outstanding debt under our
reserve-based credit facility. As of June 30, 2013, we had $21.0 million in remaining borrowing capacity under our reserve-based credit facility.
Compliance with Debt Covenants
At June 30, 2013, we were in
compliance with the financial covenants contained in our reserve-based credit facility.
6. OIL AND NATURAL GAS PROPERTIES
Oil and natural gas properties consist of the following:
|
|
|
|
|
|
|
|
|
|
|
June 30,
2013
|
|
|
December 31,
2012
|
|
|
|
(In 000s)
|
|
Oil and natural gas properties and related equipment (successful efforts method)
|
|
|
|
|
|
|
|
|
Property (acreage) costs
|
|
|
|
|
|
|
|
|
Proved property
|
|
$
|
597,178
|
|
|
$
|
591,889
|
|
Unproved property
|
|
|
1,407
|
|
|
|
1,380
|
|
|
|
|
|
|
|
|
|
|
Total property costs
|
|
|
598,585
|
|
|
|
593,269
|
|
Materials and supplies
|
|
|
1,282
|
|
|
|
771
|
|
Land
|
|
|
751
|
|
|
|
751
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
600,618
|
|
|
|
594,791
|
|
Less: Accumulated depreciation, depletion, amortization and impairments
|
|
|
(483,726
|
)
|
|
|
(474,669
|
)
|
|
|
|
|
|
|
|
|
|
Oil and natural gas properties and equipment, net
|
|
$
|
116,892
|
|
|
$
|
120,122
|
|
|
|
|
|
|
|
|
|
|
13
Depletion, depreciation, amortization and impairments consist of the following:
|
|
|
|
|
|
|
|
|
|
|
Six
Months
Ended
June 30,
2013
|
|
|
Six
Months
Ended
June 30,
2012
|
|
|
|
(In 000s)
|
|
DD&A of oil and natural gas-related assets
|
|
$
|
9,565
|
|
|
$
|
4,705
|
|
Asset Impairments
|
|
|
|
|
|
|
107
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
9,565
|
|
|
$
|
4,812
|
|
|
|
|
|
|
|
|
|
|
Impairment of Oil and Natural Gas Properties and Other Non-Current Assets
In March 2012, we recorded a total non-cash impairment charge of approximately $0.1 million to impair certain of our wells in the Woodford
Shale. This impairment was recorded because the net capitalized costs of the properties exceeded the fair value of the properties as measured by estimated cash flows reported in a third party reserve report. This report was based upon future oil and
natural gas prices, which are based on observable inputs adjusted for basis differentials, which are Level 2 inputs in the fair value hierarchy. Significant assumptions in valuing the proved reserves included the reserve quantities, anticipated
operating costs, anticipated production taxes, future expected oil and natural gas prices and basis differentials, anticipated production declines, and an appropriate discount rate commensurate with the risk of the underlying cash flow estimates for
the properties of 10.0%. The impairment was primarily caused by the impact of lower future expected oil and natural gas prices on future expected cash flows during the first quarter of 2012. After the impairments, the remaining net capitalized costs
subject to impairment in the Woodford Shale was approximately $3.6 million. Cash flow estimates for the impairment testing exclude derivative instruments used to mitigate the risk of lower future oil and natural gas prices. These asset impairments
have no impact on our cash flows, liquidity position, or debt covenants.
Asset Sales
On February 28, 2013, we sold our Robinsons Bend Field assets in the Black Warrior Basin of Alabama for $63.0 million, subject to
closing adjustments, and recorded a loss on the sale of approximately $3.1 million. These assets were classified as discontinued operations in the first quarter of 2013. In July 2013, we paid the purchaser $1.1 million, which had been held in
escrow, based on the final settlement statement. See Note 13 for additional information.
In the six months ended
June 30, 2013, we also sold miscellaneous surplus equipment for less than $0.1 million resulting in an immaterial gain on the asset sale. In the six months ended June 30, 2012, we sold our interests in 14 gross non-operated oil wells in
Kansas and Nebraska for approximately $1.4 million in cash, resulting in an immaterial loss on the asset sale.
Useful
Lives
Our furniture, fixtures, and equipment are depreciated over a life of one to five years, buildings are depreciated
over a life of twenty years, and pipeline and gathering systems are depreciated over a life of twenty-five to forty years.
Exploration and Dry Hole Costs
We had no exploration and dry hole costs in the six months ended June 30, 2013 and 2012, respectively. These costs represent abandonments of drilling locations, dry hole costs, delay rentals,
geological and geophysical costs, and the impairment, amortization, and abandonment associated with leases on our unproved properties.
7. RELATED PARTY TRANSACTIONS
Unit Ownership
Both PostRock and Exelon, through subsidiaries, own a portion of our outstanding units. As of June 30, 2013, CEPM, a subsidiary of PostRock, owned all of our Class A units and 5,918,894 of our
Class B common units. CEPH, a subsidiary of Exelon, owned all of our Class C management incentive interests and all of our Class D interests as of June 30, 2013.
Class C Management Incentive Interests
CEPH, a subsidiary of
Exelon, held all of the Class C management incentive interests in CEP as of June 30, 2013. These management incentive interests represent the right to receive 15% of quarterly distributions of available cash from operating surplus after the
Target Distribution (as defined in our operating agreement) has been achieved and certain other tests have been met. None of these applicable tests have yet to be met and CEPH has not been entitled to receive any management incentive interest
distributions.
14
8. COMMITMENTS AND CONTINGENCIES
In the course of our normal business affairs, we are subject to possible loss contingencies arising from federal, state
and local environmental, health and safety laws and regulations and third-party litigation and lawsuits. As of June 30, 2013, there were no matters which, in the opinion of management, would have a material adverse effect on the financial
position, results of operations or cash flows of CEP, and its subsidiaries, taken as a whole.
9. ASSET RETIREMENT OBLIGATION
We recognize the fair value of a liability for an asset retirement obligation (ARO) in the period in which
it is incurred if a reasonable estimate of fair value can be made. Each period, we accrete the ARO to its then present value. The associated asset retirement cost (ARC) is capitalized as part of the carrying amount of our oil and natural
gas properties, equipment and facilities. Subsequently, the ARC is depreciated using a systematic and rational method over the assets useful life. The AROs recorded by us relate to the plugging and abandonment of oil and natural gas wells, and
decommissioning of oil and natural gas gathering and other facilities.
Inherent in the fair value calculation of ARO are
numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent
future revisions to these assumptions result in adjustments to the recorded fair value of the existing ARO, a corresponding adjustment is made to the ARC capitalized as part of the oil and natural gas property balance. The following table is a
reconciliation of the ARO:
|
|
|
|
|
|
|
|
|
|
|
June 30,
2013
|
|
|
December 31,
2012
|
|
|
|
(In 000s)
|
|
Asset retirement obligation, beginning balance
|
|
$
|
7,665
|
|
|
$
|
7,052
|
|
Liabilities incurred
|
|
|
128
|
|
|
|
162
|
|
Liabilities settled
|
|
|
(3
|
)
|
|
|
(8
|
)
|
Revisions to prior estimates
|
|
|
|
|
|
|
|
|
Accretion expense
|
|
|
246
|
|
|
|
459
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation, ending balance
|
|
$
|
8,036
|
|
|
$
|
7,665
|
|
|
|
|
|
|
|
|
|
|
Additional asset retirement obligations increase the liability associated with new oil and natural gas
wells and other facilities as these obligations are incurred. Actual expenditures for abandonments of oil and natural gas wells and other facilities reduce the liability for asset retirement obligations. At June 30, 2013, and December 31,
2012, there were no significant expenditures for abandonments and there were no assets legally restricted for purposes of settling existing asset retirement obligations.
10. COMPENSATION
We recognized approximately $0.6 million and $0.7 million of non-cash compensation expense related to our unit-based
compensation plans in the six months ended June 30, 2013, and June 30, 2012, respectively. As of June 30, 2013, we had approximately $0.9 million in unrecognized compensation expense related to our unit-based non-cash compensation
plans expected to be recognized through the first quarter of 2015.
In the six months ended June 30, 2013, we incurred
one-time severance costs of approximately $1.0 million. This one-time charge was reflected as general and administrative expenses and was composed of approximately $0.8 million in cash compensation expense and approximately $0.2 million in non-cash
compensation expense related to accelerated vesting under our unit-based compensation plans.
11. DISTRIBUTIONS TO UNITHOLDERS
Beginning in June 2009, we suspended our quarterly distributions to unitholders. For each of the quarterly periods
since June 2009, we were restricted from paying distributions to unitholders as we had no available cash (taking into account the cash reserves set by our board of managers for the proper conduct of our business) from which to pay distributions.
12. MEMBERS EQUITY
2013 Equity
At June 30, 2013, we had 484,097 Class A units and 23,720,732 Class B common units outstanding, which included 44,644 unvested restricted common units issued under our Long-Term Incentive Plan
and 330,808 unvested restricted common units issued under our 2009 Omnibus Incentive Compensation Plan.
15
At June 30, 2013, we had granted 347,602 common units of the 450,000 common units
available under our Long-Term Incentive Plan. Of these grants, 302,958 have vested.
At June 30, 2013, we had granted
1,348,752 common units of the 1,650,000 common units available under our 2009 Omnibus Incentive Compensation Plan. Of these grants, 1,017,944 have vested.
For the six months ended June 30, 2013, 139,810 common units have been tendered by our employees for tax withholding purposes. These units, costing approximately $0.2 million, have been returned to
their respective plan and are available for future grants.
2012 Equity
At June 30, 2012, we had 483,531 Class A units and 23,693,018 Class B common units outstanding, which included 129,369 unvested
restricted common units issued under our Long-Term Incentive Plan and 675,919 unvested restricted common units issued under our 2009 Omnibus Incentive Compensation Plan.
At June 30, 2012, we had granted 345,221 common units of the 450,000 common units available under our Long-Term Incentive Plan. Of these grants, 215,852 have vested. We also granted an additional
76,046 performance units under our Long-Term Incentive Plan that are subject to performance conditions which vested on January 2, 2013.
At June 30, 2012, we had granted 1,323,419 common units of the 1,650,000 common units available under our 2009 Omnibus Incentive Compensation Plan. Of these grants, 647,500 have vested. We also
granted an additional 323,194 performance units under our 2009 Omnibus Incentive Compensation Plan that are subject to performance conditions which vested on January 1, 2013.
For the six months ended June 30, 2012, 78,131 common units have been tendered by our employees for tax withholding purposes. These
units, costing approximately $0.2 million, have been returned to their respective plan and are available for future grants.
13. DISCONTINUED OPERATIONS
On January 31, 2013, our Board of Managers authorized the sale of the two entities that owned all our natural gas
properties and inventory in the Robinsons Bend Field in the Black Warrior Basin of Alabama for $63.0 million, subject to closing adjustments. On February 28, 2013, we sold all of our operations in Alabama, including our interests in 596
operated natural gas wells and all of our inventory and equipment and received approximately $60.0 million in net cash proceeds from the buyer, subject to additional post-closing working capital and other customary adjustments. Of this amount,
approximately $1.2 million is being held in escrow for a period of twenty-four months pending certain closing conditions and $50.0 million was used to reduce our outstanding debt under our reserve-based credit facility. In July 2013, we paid the
purchaser $1.1 million, which had been held in escrow, based on the final settlement statement.
During the six months ended
June 30, 2013, our discontinued operations had a net loss of $2.7 million consisting of revenues of $2.3 million, expenses of $1.9 million, and a loss on sale of $3.1 million. During the six months ended June 30, 2012, our
discontinued operations had a net loss of $2.1 million consisting of revenues of $5.8 million and expenses of $7.9 million. During the three months ended June 30, 2012, our discontinued operations had a net loss of $1.3 million consisting
of revenues of $2.6 million and expenses of $4.0 million. At December 31, 2012, our discontinued operations had current assets of $1.9 million, long-term assets of $67.4 million, current liabilities of $1.6 million, and long-term liabilities of
$7.7 million. The current assets primarily represented accounts receivable for natural gas sales and the current liabilities primarily represented accounts payable and accrued liabilities. Long-term assets represented natural gas properties,
equipment and facilities and the long-term liabilities represented asset retirement obligations.
14. SUBSEQUENT EVENTS
The following subsequent events have occurred between June 30, 2013, and August 14, 2013:
Asset Acquisition and Unit Issuance
On August 9, 2013, we entered into a new business relationship with Sanchez Oil & Gas Corporation (SOG) and its affiliate, Sanchez Energy Partners I, LP (SEP I). We
acquired oil, natural gas and natural gas liquids assets in Texas and Louisiana from SEP I for a purchase price of $30.4 million. In conjunction with the acquisition, SEP I received $20.1 million in cash, 1,130,512 Class A units, which
represents 70.0% of the total Class A units outstanding after the transaction, and 4,724,407 Class B units, which represents 16.6% of the total Class B units outstanding after the transaction. The cash portion of the transaction was financed
with cash on hand and a borrowing of $16.7 million under CEPs reserved-based credit facility.
16
The acquired assets include 67 wells, 75% operated by SOG, with current net production of
approximately 1,167 Boe per day, of which approximately 25% is oil and natural gas liquids production.
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with the financial statements and the summary of
significant accounting policies and notes included herein and in our most recent Annual Report on Form 10-K.
Overview
We are a limited liability company formed in 2005 to acquire oil and natural gas properties. All of our oil and natural gas reserves are
currently located in the Mid-Continent region of the United States, including the Cherokee Basin of Kansas and Oklahoma, the Woodford Shale in Oklahoma, the Central Kansas Uplift in Kansas and Sanchez Gulf Coast properties in Texas and Louisiana.
Our primary business objective is to create long-term value and to generate stable cash flows allowing us to invest in our business to grow our reserves and production. We plan to achieve our objective by executing our business strategy, which
is to:
|
|
|
organically grow our business by increasing reserves and production through what we believe to be low-risk development drilling that focuses on capital
efficient production growth and oil opportunities on our existing properties in the Mid-Continent region;
|
|
|
|
reduce the volatility in our cash flows resulting from changes in oil and natural gas commodity prices and interest rates through efficient hedging
programs; and
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|
make accretive, right-sized acquisitions of oil and natural gas properties characterized by a high percentage of proved developed oil and natural gas
reserves with long-lived, stable production and low-risk drilling opportunities.
|
We completed our initial
public offering on November 20, 2006, and our Class B common units are currently listed on the NYSE MKT under the symbol CEP.
Unless the context requires otherwise, any reference in this Quarterly Report on Form 10-Q to Constellation Energy Partners, we, our, us, CEP,
or the Company means Constellation Energy Partners LLC and its subsidiaries. References in this Quarterly Report on Form 10-Q to PostRock and CEPM are to PostRock Energy Corporation and its subsidiary
Constellation Energy Partners Management, LLC, respectively. References in this Quarterly Report on Form 10-Q to Exelon and CEPH are to Exelon Corporation and its subsidiary Constellation Energy Partners Holdings, LLC,
respectively. References in this Quarterly Report on Form 10-Q to Constellation, CCG, and CHI are to Constellation Energy Group, Inc., Constellation Energy Commodities Group, Inc., and Constellation Holdings,
Inc., respectively.
How We Evaluate our Operations
Non-GAAP Financial MeasureAdjusted EBITDA
We define Adjusted EBITDA
as net income (loss) adjusted by:
|
|
|
depreciation, depletion and amortization;
|
|
|
|
write-off of deferred financing fees;
|
|
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|
(gain) loss on sale of assets;
|
|
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|
(gain) loss from equity investment;
|
|
|
|
unit-based compensation programs;
|
|
|
|
(gain) loss from mark-to-market activities;
|
|
|
|
gains (losses) on discontinued operations; and
|
|
|
|
interest (income) expense, net which includes:
|
|
|
|
interest expense gain/(loss) mark-to-market activities
|
17
Adjusted EBITDA is a significant performance metric used by our management to indicate
(prior to the establishment of any cash reserves by our board of managers) the distributions we would expect to pay to our unitholders. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level
that can sustain or support a quarterly distribution or any increase in our quarterly distribution rates. Adjusted EBITDA is also used as a quantitative standard by our management and by external users of our financial statements such as investors,
research analysts, our lenders and others to assess:
|
|
|
the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
|
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|
|
the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness; and
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|
our operating performance and return on capital as compared to those of other companies in our industry, without regard to financing or capital
structure.
|
Our Adjusted EBITDA should not be considered as a substitute for net income, operating income,
cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA excludes some, but not all, items that affect net income and operating income and these measures
may vary among other companies. Therefore, our Adjusted EBITDA may not be comparable to similarly titled measures of other companies.
We are unable to reconcile our forecast range of Adjusted EBITDA to GAAP net income or operating income because we do not predict the future impact of adjustments to net income (loss), such as (gains)
losses from mark-to-market activities and equity investments or asset impairments due to the difficulty of doing so, and we are unable to address the probable significance of the unavailable reconciliation, in significant part due to ranges in our
forecast impacted by changes in oil and natural gas prices and reserves which affect certain reconciliation items.
The
following table presents a reconciliation of net income (loss) to Adjusted EBITDA, our most directly comparable GAAP performance measure, for each of the periods presented:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended
|
|
|
For the Six Months Ended
|
|
|
|
June 30,
2013
|
|
|
June 30,
2012
|
|
|
June 30,
2013
|
|
|
June 30,
2012
|
|
|
|
( In 000s)
|
|
Net income (loss)
|
|
$
|
1,112
|
|
|
$
|
(5,010
|
)
|
|
$
|
(12,220
|
)
|
|
$
|
875
|
|
Adjusted by:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense/(income), net
|
|
|
864
|
|
|
|
1,437
|
|
|
|
2,216
|
|
|
|
3,056
|
|
Depreciation, depletion and amortization
|
|
|
4,767
|
|
|
|
2,318
|
|
|
|
9,565
|
|
|
|
4,705
|
|
Asset impairments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
107
|
|
Accretion expense
|
|
|
123
|
|
|
|
115
|
|
|
|
246
|
|
|
|
229
|
|
(Gain)/Loss on sale of assets
|
|
|
(17
|
)
|
|
|
(4
|
)
|
|
|
(23
|
)
|
|
|
|
|
Unit-based compensation programs
|
|
|
208
|
|
|
|
385
|
|
|
|
609
|
|
|
|
665
|
|
(Gain)/Loss on mark-to-market activities
|
|
|
(2,346
|
)
|
|
|
4,897
|
|
|
|
6,939
|
|
|
|
(1,705
|
)
|
Discontinued operations
|
|
|
|
|
|
|
1,331
|
|
|
|
2,686
|
|
|
|
2,132
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
4,711
|
|
|
$
|
5,469
|
|
|
$
|
10,018
|
|
|
$
|
10,064
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our Adjusted EBITDA from our continuing operations was $4.7 million for the three months ended
June 30, 2013, which is lower than our Adjusted EBITDA of $5.5 million in the same period in 2012. The decrease is mostly due to gains on our mark-to-market activities, lower production and higher depreciation, depletion and amortization.
Our Adjusted EBITDA was $10.0 million for the six months ended June 30, 2013, lower than our Adjusted EBITDA of $10.1
million in the same period in 2012.
Some key highlights of our business activities through August 14, 2013 were:
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|
We refinanced our credit facility, and increased our borrowing base from $37.5 million to $55.0 million.
|
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|
|
We sold all of our natural gas properties in the Robinsons Bend Field in the Black Warrior Basin of Alabama in February 2013.
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|
We have implemented strategies to reduce our general and administrative expenses and our lease operating expenses going forward. During the first six
months of 2013, we incurred a general and administrative charges of approximately $1.0 million associated with severance costs. Excluding this charge and non-cash unit-based compensation costs, our six months ended June 30, 2013 cash general
and administrative expenses and lease operating expenses decreased by 11.2% as compared to these cash operating expenses for the same time period in 2012.
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|
Our successful capital expenditure programs have continued to expand our oil production. Our six months ended June 30, 2013 oil production has
increased by 54% over our oil production for the same time period in 2012. Oil revenues accounted for 42.6% of our total unhedged revenue stream in 2013.
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|
We acquired oil, natural gas and natural gas liquids assets in Texas and Louisiana from SEP I for a purchase price of $30.4 million.
|
18
In 2013, we intend to continue focusing our efforts on developing oil opportunities on our
existing properties in the Mid-continent region while pursuing opportunities to acquire additional properties in our operating area or merger and acquisition opportunities. Our forecasted capital spending of $19 million to $21 million is unchanged,
with maintenance capital spending setting the high end of this range. We anticipate that our 2013 capital expenditures could allow us to maintain our 2013 production at slightly below the same level as in 2012. We intend to manage our business to
operate within the cash flows that are generated by our existing asset base.
Significant Operational Factors
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Realized Prices.
Our average realized price for the six months ended June 30, 2013, was $7.11 per Mcfe including hedge settlements and
$5.09 per Mcfe excluding hedge settlements. After deducting the cost of sales associated with our third party gathering, our average realized prices were $6.90 per Mcfe including hedge settlements and $4.88 per Mcfe excluding hedge settlements.
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|
Production.
Our production for the six months ended June 30, 2013, was 3.9 Bcfe, or an average of 21,322 Mcfe per day, compared with
approximately 4.2 Bcfe, or an average of 22,830 Mcfe per day, for the six months ended June 30, 2012. Our oil production increased 55.2% for the six months ended June 30, 2013 when compared to the same period in 2012. Our 2013 production
is lower than the production for the same period in 2012 because of the natural production declines associated with our existing natural gas wells not being fully offset by the impact of our drilling programs which were limited so that our operating
cash flows could be used to reduce our outstanding debt level.
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|
|
Capital Expenditures and Drilling Results.
During the first six months of 2013, we spent approximately $6.4 million in cash capital
expenditures, consisting of $6.3 million in development expenditures focused on oil completions in the Cherokee Basin and $0.1 million to acquire certain additional natural gas wells in the Cherokee Basin. We have completed 26 net wells and 13 net
recompletions during the six months ended June 30, 2013 and have 5 net wells and net recompletions in progress at June 30, 2013. During the fourth quarter of 2012 and the first quarter of 2013, we successfully completed substantially all
of the remaining net wells and net recompletions from our 2012 capital program, and the first six months of 2013 daily average net oil production has increased to 500 barrels from our average daily production of 324 barrels for the second quarter of
2012.
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|
|
Hedging Activities
. All of our commodity and interest rate derivatives are accounted for as mark-to-market activities. For the six months ended
June 30, 2013, the unrealized non-cash mark-to-market loss for our commodity derivatives was approximately $6.9 million as compared to an unrealized non-cash mark-to-market gain of $1.7 million for the same period in 2012.
|
We experience earnings volatility as a result of using the mark-to-market accounting method for our open
derivative positions. This accounting treatment can cause extreme earnings volatility as the positions for future oil and natural gas production or interest rates are marked-to-market. These non-cash unrealized gains or losses are included in our
current statement of operations until the derivatives are cash settled as the commodities are produced and sold or interest payments are made. Further detail of our commodity derivative positions and their accounting treatment is outlined below in
Cash Flow From Operations-Open Commodity Hedge Position.
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|
|
Debt Reduction
. We have reduced our outstanding debt from a high of $220.0 million in 2009 to $34.0 million as of June 30, 2013, or by
84.5% in total. At August 14, 2013, we had $50.7 million in outstanding debt with $4.3 remaining in borrowing capacity in connection with our acquisition of SEP I assets.
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|
|
|
Operating Expense Reductions
. We have implemented strategies to reduce our structural general and administrative expenses by 25% for 2013 and to
further reduce our lease operating expenses. These strategies include: reducing headcount in Houston and Oklahoma, closing our technical office in Tulsa, Oklahoma, closing our field office in Dewey, Oklahoma, lowering our annual bonus expense by
50%, reducing executive and board compensation expenses, reducing medical and dental plan expenses by changing providers, reducing the employer match for our 401K program, releasing our strategic advisor, changing certain other professional services
providers, terminating our outsource support services agreement for revenue accounting services, and reducing overtime expenses.
|
19
Results of Operations
The following table sets forth the selected financial and operating data for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended
|
|
|
For the Six Months Ended
|
|
|
|
(Dollars in 000s)
|
|
|
|
June 30,
2013
|
|
|
June 30,
2012
|
|
|
Variance
|
|
|
June 30,
2013
|
|
|
June 30,
2012
|
|
|
Variance
|
|
|
|
|
|
|
|
|
|
$
|
|
|
%
|
|
|
|
|
|
|
|
|
$
|
|
|
%
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales at market price
|
|
$
|
5,228
|
|
|
$
|
3,211
|
|
|
$
|
2,017
|
|
|
|
62.8
|
%
|
|
$
|
9,619
|
|
|
$
|
7,047
|
|
|
$
|
2,572
|
|
|
|
36.5
|
%
|
Natural gas hedge settlements
|
|
|
2,730
|
|
|
|
7,307
|
|
|
|
(4,577
|
)
|
|
|
(62.6
|
)%
|
|
|
7,274
|
|
|
|
13,265
|
|
|
$
|
(5,991
|
)
|
|
|
(45.2
|
)%
|
Natural gas mark-to-market activities
|
|
|
1,352
|
|
|
|
(8,455
|
)
|
|
|
9,807
|
|
|
|
(116.0
|
)%
|
|
|
(7,129
|
)
|
|
|
(583
|
)
|
|
$
|
(6,546
|
)
|
|
|
1,122.8
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas total
|
|
|
9,310
|
|
|
|
2,063
|
|
|
|
7,247
|
|
|
|
351.3
|
%
|
|
|
9,764
|
|
|
|
19,729
|
|
|
|
(9,965
|
)
|
|
|
(50.5
|
)%
|
Oil and liquids sales
|
|
$
|
4,023
|
|
|
$
|
2,866
|
|
|
$
|
1,157
|
|
|
|
40.4
|
%
|
|
$
|
8,374
|
|
|
$
|
6,057
|
|
|
$
|
2,317
|
|
|
|
38.3
|
%
|
Oil hedge settlements
|
|
|
346
|
|
|
$
|
34
|
|
|
|
312
|
|
|
|
917.6
|
%
|
|
|
507
|
|
|
|
123
|
|
|
|
384
|
|
|
|
312.2
|
%
|
Oil mark-to-market activities
|
|
|
994
|
|
|
$
|
3,558
|
|
|
|
(2,564
|
)
|
|
|
(72.1
|
)%
|
|
|
190
|
|
|
|
2,288
|
|
|
|
(2,098
|
)
|
|
|
(91.7
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and liquids total
|
|
|
5,363
|
|
|
|
6,458
|
|
|
|
(1,095
|
)
|
|
|
(17.0
|
)%
|
|
|
9,071
|
|
|
|
8,468
|
|
|
|
603
|
|
|
|
7.1
|
%
|
Other natural gas sales at market price
|
|
$
|
715
|
|
|
$
|
678
|
|
|
$
|
37
|
|
|
|
5.5
|
%
|
|
$
|
1,653
|
|
|
$
|
1,616
|
|
|
$
|
37
|
|
|
|
2.3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
15,388
|
|
|
$
|
9,199
|
|
|
$
|
6,189
|
|
|
|
67.3
|
%
|
|
$
|
20,488
|
|
|
$
|
29,813
|
|
|
$
|
(9,325
|
)
|
|
|
(31.3
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
3,905
|
|
|
|
4,687
|
|
|
|
(782
|
)
|
|
|
(16.7
|
)%
|
|
|
8,141
|
|
|
|
9,858
|
|
|
|
(1,717
|
)
|
|
|
(17.4
|
)%
|
Cost of sales
|
|
|
379
|
|
|
|
251
|
|
|
|
128
|
|
|
|
51.0
|
%
|
|
|
799
|
|
|
|
636
|
|
|
|
163
|
|
|
|
25.6
|
%
|
Production taxes
|
|
|
622
|
|
|
|
365
|
|
|
|
257
|
|
|
|
70.4
|
%
|
|
|
1,109
|
|
|
|
767
|
|
|
|
342
|
|
|
|
44.6
|
%
|
General and administrative
|
|
|
3,737
|
|
|
|
3,705
|
|
|
|
32
|
|
|
|
0.9
|
%
|
|
|
8,141
|
|
|
|
7,541
|
|
|
|
600
|
|
|
|
8.0
|
%
|
Gain on sale of assets
|
|
|
(17
|
)
|
|
|
(4
|
)
|
|
|
(13
|
)
|
|
|
325.0
|
%
|
|
|
(23
|
)
|
|
|
|
|
|
|
(23
|
)
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
4,767
|
|
|
|
2,318
|
|
|
|
2,449
|
|
|
|
105.7
|
%
|
|
|
9,565
|
|
|
|
4,705
|
|
|
|
4,860
|
|
|
|
103.3
|
%
|
Asset impairments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
107
|
|
|
|
(107
|
)
|
|
|
(100.0
|
)%
|
Accretion expenses
|
|
|
123
|
|
|
|
115
|
|
|
|
8
|
|
|
|
7.0
|
%
|
|
|
246
|
|
|
|
229
|
|
|
|
17
|
|
|
|
7.4
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
13,516
|
|
|
|
11,437
|
|
|
|
2,079
|
|
|
|
18.2
|
%
|
|
|
27,978
|
|
|
|
23,843
|
|
|
|
4,135
|
|
|
|
17.3
|
%
|
Other expenses (income):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
1,848
|
|
|
|
1,951
|
|
|
|
(103
|
)
|
|
|
(5.3
|
)%
|
|
|
5,864
|
|
|
|
3,662
|
|
|
|
2,202
|
|
|
|
60.1
|
%
|
Interest expense-Gain from mark-to-market activities
|
|
|
(984
|
)
|
|
|
(513
|
)
|
|
|
(471
|
)
|
|
|
91.8
|
%
|
|
|
(3,648
|
)
|
|
|
(605
|
)
|
|
|
(3,043
|
)
|
|
|
503.0
|
%
|
Interest income
|
|
|
|
|
|
|
(1
|
)
|
|
|
1
|
|
|
|
(100.0
|
)%
|
|
|
|
|
|
|
(1
|
)
|
|
|
1
|
|
|
|
(100.0
|
)%
|
Other (income) expense
|
|
|
(104
|
)
|
|
|
4
|
|
|
|
(108
|
)
|
|
|
(2,700.0
|
)%
|
|
|
(172
|
)
|
|
|
(93
|
)
|
|
|
(79
|
)
|
|
|
84.9
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expenses
|
|
|
760
|
|
|
|
1,441
|
|
|
|
(681
|
)
|
|
|
(47.3
|
)%
|
|
|
2,044
|
|
|
|
2,963
|
|
|
|
(919
|
)
|
|
|
(31.0
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
14,276
|
|
|
|
12,878
|
|
|
|
1,398
|
|
|
|
10.9
|
%
|
|
|
30,022
|
|
|
|
26,806
|
|
|
|
3,216
|
|
|
|
12.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued operations
|
|
|
|
|
|
|
(1,331
|
)
|
|
|
1,331
|
|
|
|
(100.0
|
)%
|
|
|
(2,686
|
)
|
|
|
(2,132
|
)
|
|
|
(554
|
)
|
|
|
26.0
|
%
|
Net income (loss)
|
|
$
|
1,112
|
|
|
$
|
(5,010
|
)
|
|
$
|
6,122
|
|
|
|
(122.2
|
)%
|
|
$
|
(12,220
|
)
|
|
$
|
875
|
|
|
$
|
(13,095
|
)
|
|
|
(1,496.6
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas production (MMcf)
|
|
|
1,593
|
|
|
|
1,857
|
|
|
|
(264
|
)
|
|
|
(14.2
|
)%
|
|
|
3,316
|
|
|
|
3,802
|
|
|
|
(486
|
)
|
|
|
(12.8
|
)%
|
Oil and liquids production (MBbl)
|
|
|
43
|
|
|
|
29
|
|
|
|
14
|
|
|
|
48.3
|
%
|
|
|
90
|
|
|
|
58
|
|
|
|
32
|
|
|
|
55.2
|
%
|
Total production (MMcfe)
|
|
|
1,849
|
|
|
|
2,033
|
|
|
|
(184
|
)
|
|
|
(9.1
|
)%
|
|
|
3,859
|
|
|
|
4,155
|
|
|
|
(296
|
)
|
|
|
(7.1
|
)%
|
Average daily production (Mcfe/d)
|
|
|
20,315
|
|
|
|
22,341
|
|
|
|
(2,026
|
)
|
|
|
(9.1
|
)%
|
|
|
21,322
|
|
|
|
22,830
|
|
|
|
(1,508
|
)
|
|
|
(6.6
|
)%
|
Total production (MBOE)
|
|
|
308
|
|
|
|
339
|
|
|
|
(31
|
)
|
|
|
(9.1
|
)%
|
|
|
643
|
|
|
|
692
|
|
|
|
(49
|
)
|
|
|
(7.1
|
)%
|
Average daily production (BOE/d)
|
|
|
3,386
|
|
|
|
3,720
|
|
|
|
(334
|
)
|
|
|
(9.0
|
)%
|
|
|
3,553
|
|
|
|
3,800
|
|
|
|
(247
|
)
|
|
|
(6.5
|
)%
|
Average sales prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas price per Mcf with hedge settlements
|
|
$
|
5.45
|
|
|
$
|
6.03
|
|
|
$
|
(0.58
|
)
|
|
|
(9.6
|
)%
|
|
$
|
5.59
|
|
|
$
|
5.77
|
|
|
$
|
(0.18
|
)
|
|
|
(3.1
|
)%
|
Natural gas price per Mcf without hedge settlements
|
|
$
|
3.73
|
|
|
$
|
2.09
|
|
|
$
|
1.64
|
|
|
|
78.5
|
%
|
|
$
|
3.40
|
|
|
$
|
2.28
|
|
|
$
|
1.12
|
|
|
|
49.1
|
%
|
Oil and liquids price per Bbl with hedge settlements
|
|
$
|
102.32
|
|
|
$
|
100.00
|
|
|
$
|
2.32
|
|
|
|
2.3
|
%
|
|
$
|
98.24
|
|
|
$
|
106.55
|
|
|
$
|
(8.31
|
)
|
|
|
(7.8
|
)%
|
Oil and liquids price per Bbl without hedge settlements
|
|
$
|
94.22
|
|
|
$
|
98.83
|
|
|
$
|
(4.61
|
)
|
|
|
(4.7
|
)%
|
|
$
|
92.63
|
|
|
$
|
104.43
|
|
|
$
|
(11.80
|
)
|
|
|
(11.3
|
)%
|
20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended
|
|
|
For the Six Months Ended
|
|
|
|
(Dollars in 000s)
|
|
|
|
June 30,
2013
|
|
|
June 30,
2012
|
|
|
Variance
|
|
|
June 30,
2013
|
|
|
June 30,
2012
|
|
|
Variance
|
|
|
|
|
|
|
|
|
|
$
|
|
|
%
|
|
|
|
|
|
|
|
|
$
|
|
|
%
|
|
Total price per Mcfe with hedge settlements
|
|
$
|
7.05
|
|
|
$
|
6.93
|
|
|
$
|
0.12
|
|
|
|
1.7
|
%
|
|
$
|
7.11
|
|
|
$
|
6.76
|
|
|
$
|
0.35
|
|
|
|
5.2
|
%
|
Total price per Mcfe without hedge settlements
|
|
$
|
5.39
|
|
|
$
|
3.32
|
|
|
$
|
2.07
|
|
|
|
62.3
|
%
|
|
$
|
5.09
|
|
|
$
|
3.54
|
|
|
$
|
1.55
|
|
|
|
43.8
|
%
|
Total price per BOE with hedge settlements
|
|
$
|
42.33
|
|
|
$
|
41.64
|
|
|
$
|
0.69
|
|
|
|
1.7
|
%
|
|
$
|
42.65
|
|
|
$
|
40.64
|
|
|
$
|
2.01
|
|
|
|
4.9
|
%
|
Total price per BOE without hedge settlements
|
|
$
|
32.34
|
|
|
$
|
19.96
|
|
|
$
|
12.38
|
|
|
|
62.0
|
%
|
|
$
|
30.55
|
|
|
$
|
21.28
|
|
|
$
|
9.27
|
|
|
|
43.6
|
%
|
Average unit costs per Mcfe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Field operating expenses
(a)
|
|
$
|
2.45
|
|
|
$
|
2.47
|
|
|
$
|
(0.02
|
)
|
|
|
(0.8
|
)%
|
|
$
|
2.40
|
|
|
$
|
2.56
|
|
|
$
|
(0.16
|
)
|
|
|
(6.3
|
)%
|
Lease operating expenses
|
|
$
|
2.11
|
|
|
$
|
2.31
|
|
|
$
|
(0.20
|
)
|
|
|
(8.6
|
)%
|
|
$
|
2.11
|
|
|
$
|
2.37
|
|
|
$
|
(0.26
|
)
|
|
|
(11.0
|
)%
|
Production taxes
|
|
$
|
0.34
|
|
|
$
|
0.18
|
|
|
$
|
0.16
|
|
|
|
88.9
|
%
|
|
$
|
0.29
|
|
|
$
|
0.18
|
|
|
$
|
0.11
|
|
|
|
61.1
|
%
|
General and administrative
|
|
$
|
2.02
|
|
|
$
|
1.82
|
|
|
$
|
0.20
|
|
|
|
11.0
|
%
|
|
$
|
2.11
|
|
|
$
|
1.81
|
|
|
$
|
0.30
|
|
|
|
16.6
|
%
|
General and administrative w/o unit-based compensation
|
|
$
|
1.91
|
|
|
$
|
1.64
|
|
|
$
|
0.27
|
|
|
|
16.5
|
%
|
|
$
|
1.95
|
|
|
$
|
1.66
|
|
|
$
|
0.29
|
|
|
|
17.5
|
%
|
Depreciation, depletion and amortization
|
|
$
|
2.58
|
|
|
$
|
1.14
|
|
|
$
|
1.44
|
|
|
|
126.3
|
%
|
|
$
|
2.48
|
|
|
$
|
1.13
|
|
|
$
|
1.35
|
|
|
|
119.5
|
%
|
Average unit costs per BOE:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Field operating expenses
(a)
|
|
$
|
14.69
|
|
|
$
|
14.92
|
|
|
$
|
(0.23
|
)
|
|
|
(1.5
|
)%
|
|
$
|
14.38
|
|
|
$
|
15.36
|
|
|
$
|
(0.98
|
)
|
|
|
(6.4
|
)%
|
Lease operating expenses
|
|
$
|
12.67
|
|
|
$
|
13.85
|
|
|
$
|
(1.18
|
)
|
|
|
(8.5
|
)%
|
|
$
|
12.66
|
|
|
$
|
14.25
|
|
|
$
|
(1.59
|
)
|
|
|
(11.2
|
)%
|
Production taxes
|
|
$
|
2.02
|
|
|
$
|
1.08
|
|
|
$
|
0.94
|
|
|
|
87.0
|
%
|
|
$
|
1.72
|
|
|
$
|
1.11
|
|
|
$
|
0.61
|
|
|
|
55.0
|
%
|
General and administrative
|
|
$
|
12.13
|
|
|
$
|
10.95
|
|
|
$
|
1.18
|
|
|
|
10.8
|
%
|
|
$
|
12.66
|
|
|
$
|
10.90
|
|
|
$
|
1.76
|
|
|
|
16.1
|
%
|
General and administrative w/o unit-based compensation
|
|
$
|
11.45
|
|
|
$
|
9.84
|
|
|
$
|
1.61
|
|
|
|
16.4
|
%
|
|
$
|
11.72
|
|
|
$
|
9.96
|
|
|
$
|
1.76
|
|
|
|
17.7
|
%
|
Depreciation, depletion and amortization
|
|
$
|
15.47
|
|
|
$
|
6.85
|
|
|
$
|
8.62
|
|
|
|
125.8
|
%
|
|
$
|
14.87
|
|
|
$
|
6.80
|
|
|
$
|
8.07
|
|
|
|
118.7
|
%
|
(a)
|
Field operating expenses include lease operating expenses (average production costs) and production taxes.
|
Three months ended June 30, 2013 compared to three months ended June 30, 2012
Oil and natural gas sales.
Oil and liquid sales unhedged increased $1.1 million, or 40.4%, to $4.0 million for the three months
ended June 30, 2013 as compared to $2.9 million for the same period in 2012. Natural gas sales unhedged increased $2.0 million, or 62.8%, to $5.2 million for the three months ended June 30, 2013 as compared to $3.2 million for the same
period in 2012. With hedges and mark-to-market activities, our total revenue increased $6.2 million when compared to the same period in 2012. Of this increase, $3.8 million was attributable to higher market prices for our natural gas production and
higher market prices for our oil production, $7.3 million in higher mark-to-market activities offset by $4.3 million attributable to lower cash hedge settlements from our hedge program, and $0.6 million attributable to decreased natural gas
production volumes offset by higher oil volumes. Production for the three months ended June 30, 2013 was 1.8 Bcfe, which was 0.2 Bcfe lower than the same period in 2012. This decrease was associated with natural declines in our natural gas
production in the Cherokee Basin not being fully offset by increases in our oil production. The production from our Woodford Shale properties remained level. Due to the decrease in the level of our drilling activities since 2010, our maintenance
drilling programs have not been sufficient to offset the natural decline rate of production associated with our wells owned as of June 30, 2013. We hedged all of our actual consolidated production volumes sold through June 30, 2013, and
approximately 75% of our actual production through June 30, 2012. In March 2013, we liquidated or repositioned certain of our hedges to ensure that our outstanding derivative positions in future periods are lower than our expected future
natural gas production in those periods.
Cash hedge settlements received for our commodity derivatives were approximately
$3.1 million for the three months ended June 30, 2013. Cash hedge settlements received for our commodity derivatives were approximately $7.3 million for the three months ended June 30, 2012. This difference is due to changes in hedge
prices, hedged volumes, and market prices for natural gas and oil during 2012.
As discussed below, our unrealized non-cash
mark-to-market activities increased by $7.2 million for the three months ended June 30, 2013, as compared to the same period in 2012. Our realized prices before our hedging program increased from 2012 to 2013 primarily due to net higher
market prices for our natural gas production. This was offset by our hedging program and the mark-to-market gains and losses discussed below.
21
Hedging and mark-to-market activities.
All of our derivatives are accounted for as
mark-to-market activities. For the three months ended June 30, 2013, the unrealized non-cash mark-to-market gain was approximately $2.3 million as compared to an unrealized non-cash mark-to-market loss of $4.9 million for the same period in
2012. The 2013 non-cash gain represents approximately $2.4 million from the impact of lower future expected oil and natural gas prices on these derivative transactions that are being accounted for as mark-to-market activities and a $0.1 million loss
related to non-performance risk associated with our counterparties. The 2012 non-cash loss represented approximately $5.1 million from the impact of future expected oil and natural gas prices on these derivative transactions that are being accounted
for as mark-to-market activities, offset by $0.2 million related to non-performance risk associated with our counterparties.
Field operating expenses.
Our field operating expenses generally consist of lease operating expenses, labor, vehicle, supervision,
transportation, minor maintenance, tools and supplies expenses, as well as production and ad valorem taxes.
For the three
months ended June 30, 2013, lease operating expenses decreased $0.8 million, or 16.7%, to $3.9 million, compared to expenses of $4.7 million for the same period in 2012. This decrease in lease operating expenses is primarily related to $0.8
million in lower expenses in the Cherokee Basin. By category, our lease operating expenses were lower in 2013 as compared to 2012 by $0.8 million because of decreases of $0.4 million in elective costs such as well servicing and repairs and
maintenance, $0.3 million in lower insurance and $0.1 million in lower ad valorem taxes.
For the three months ended
June 30, 2013, per unit lease operating expenses were $2.11 per Mcfe compared to $2.31 per Mcfe for the same period in 2012.
For the three months ended June 30, 2013, production taxes increased $0.2 million, or 70.4%, to $0.6 million, compared to expenses of $0.4 million for the same period in 2012. This increase is
primarily the result of higher market prices for natural gas and oil in 2013 offset by the impact of production taxes on 0.2 Bcfe in lower production in 2013.
Cost of sales.
For the three months ended June 30, 2013, cost of sales remained flat compared to the same period in 2012.
General and administrative expenses.
General and administrative expenses include the costs of our employees, related benefits,
field office expenses, professional fees, and other costs not directly associated with field operations. General and administrative expenses remained flat at $3.7 million for the three months ended June 30, 2013, as compared to $3.7 million for
the same period in 2012. Without severance costs of $0.2 million incurred during the three months ended June 30, 2013, our total reported general and administrative expenses for the three months ended June 30, 2013, would have been lower by
approximately $0.2 million as compared to the same period in 2012.
Our per unit costs were $2.01 per Mcfe for the three
months ended June 30, 2013, as compared to $1.82 per Mcfe for the same period in 2012. This increase is attributable to the impact of 0.2 Bcfe in lower production.
Gain on sale of asset.
Our gain on the sale of assets increased approximately $0.01 million, or 325.0%, to a gain of less than $0.02 million for the three months ended June 30, 2013, as
compared to a gain of less than $0.01 million for the same period in 2012. In 2013, we sold trucks and surplus equipment in Oklahoma at a gain of less than $0.02 million. In 2012, we sold trucks and surplus equipment at a gain of less than $0.01
million.
Depreciation, depletion and amortization expense and Asset Impairments.
Depreciation, depletion and
amortization expenses include the depreciation, depletion and amortization of acquisition costs and equipment costs. Depletion is calculated using units-of-production under the successful efforts method of accounting. Assuming everything else
remains unchanged, as oil or natural gas production changes, depletion would change in the same direction.
Our depreciation,
depletion and amortization expense for the three months ended June 30, 2013 was $4.8 million, or $2.58 per Mcfe, compared to $2.3 million, or $1.14 per Mcfe, for the same period in 2012. This increase in 2013 depreciation, depletion, and
amortization reflects the decrease in our reserve base at December 31, 2012, primarily due to the impact of a lower SEC-required natural gas price used to calculate our reserves which resulted in negative reserve revisions, and increased
expenditures incurred for our drilling programs in 2012. These revisions were partially offset by increased oil reserves as a result of our successful drilling programs and a 0.2 Bcfe decrease in production volumes during 2013 as compared to 2012.
Our other assets are depreciated using the straight-line basis. Consistent with our prior practice, we will use our 2012 reserve report to calculate our depletion rate during the first three quarters of 2013 and will use our 2013 reserve report to
record our depletion in the fourth quarter of 2013.
For the three months ended June 30, 2013 and June 30, 2012, no
asset impairment was recorded.
Interest expense.
Interest expense for the three months ended June 30, 2013
decreased $0.6 million, or 40.0%, to $0.9 million as compared to $1.5 million in interest expense for the same period in 2012. This decrease was primarily due to $0.5 million in higher non-cash mark-to-market gains on our interest rate swaps that
are accounted for as mark-to-market activities, lower market interest expense on our outstanding debt of $0.3 million, and higher interest rate swap settlements of $0.2 million, while capitalized interest remained flat in 2013 to the same period in
2012. At June 30, 2013, we had an outstanding balance under our reserve-based credit facility of $34.0 million as compared to $88.4 million at June 30, 2012. The average interest rate on our outstanding debt was approximately 3.192% at
June 30, 2013 compared to 6.0% during the same period in 2012.
22
Interest income.
Interest income for the three months ended June 30, 2013, was
less than $0.01 million as compared to less than $0.01 million for the same period in 2012. During 2013, market rates for overnight investments continued to be at historical lows, resulting in no significant earnings on our cash balances.
Six months ended June 30, 2013 compared to six months ended June 30, 2012
Oil and natural gas sales.
Oil and liquid sales unhedged increased $2.3 million, or 38.3%, to $8.4 million for the six months ended
June 30, 2013 as compared to $6.1 million for the same period in 2012. Natural gas sales unhedged increased $2.6 million, or 36.5%, to $9.6 million for the six months ended June 30, 2013 as compared to $7.0 million for the same period in
2012. With hedges and mark-to-market activities, our total revenue decreased $9.3 million when compared to the same period in 2012. Of this decrease, $8.6 million in lower mark-to-market activities, $5.6 million attributable to lower cash hedge
settlements from our hedge program, and $1.0 million attributable to decreased natural gas production volumes offset by $6.0 million was attributable to higher market prices for our natural gas production and higher market prices for our oil
production and by higher oil volumes. Production for the six months ended June 30, 2013 was 3.9 Bcfe, which was 0.3 Bcfe lower than the same period in 2012. This decrease was associated with natural declines in our natural gas production in the
Cherokee Basin not being fully offset by increases in our oil production. The production from our Woodford Shale properties remained level. Due to the decrease in the level of our drilling activities since 2010, our maintenance drilling programs
have not been sufficient to offset the natural decline rate of production associated with our wells owned as of June 30, 2013. We hedged all of our actual consolidated production volumes sold through June 30, 2013, and approximately 74% of
our actual production through June 30, 2012. In March 2013, we liquidated or repositioned certain of our hedges to ensure that our outstanding derivative positions in future periods are lower than our expected future natural gas production in
those periods.
Cash hedge settlements received for our commodity derivatives were approximately $7.8 million for the six
months ended June 30, 2013. Cash hedge settlements received for our commodity derivatives were approximately $13.4 million for the six months ended June 30, 2012. This difference is due to changes in hedge prices, hedged volumes, and
market prices for natural gas and oil during 2012.
As discussed below, our unrealized non-cash mark-to-market activities
decreased by $8.6 million for the six months ended June 30, 2013, as compared to the same period in 2012. Our realized prices before our hedging program increased from 2012 to 2013 primarily due to net higher market prices for our natural
gas production. This was offset by our hedging program and the mark-to-market gains and losses discussed below.
Hedging
and mark-to-market activities.
All of our derivatives are accounted for as mark-to-market activities. For the six months ended June 30, 2013, the unrealized non-cash mark-to-market loss was approximately $6.9 million as compared to an
unrealized non-cash mark-to-market gain of $1.7 million for the same period in 2012. These losses represent the change in the estimated fair value of our open derivative positions for each period. The 2013 non-cash loss represents approximately $6.8
million from the impact of higher future expected oil and natural gas prices on these derivative transactions that are being accounted for as mark-to-market activities and a $0.1 million loss related to non-performance risk associated with our
counterparties. The 2012 non-cash gain represented approximately $2.2 million from the impact of lower than expected future natural gas prices on these derivative transactions that are being accounted for as mark-to-market activities offset by a
$0.5 million reduction for non-performance risk related to our counterparties.
Field operating expenses.
Our field
operating expenses generally consist of lease operating expenses, labor, vehicle, supervision, transportation, minor maintenance, tools and supplies expenses, as well as production and ad valorem taxes.
For the six months ended June 30, 2013, lease operating expenses decreased $1.7 million, or 17.4%, to $8.2 million, compared to
expenses of $9.9 million for the same period in 2012. This decrease in lease operating expenses is primarily related to $1.7 million in lower expenses in the Cherokee Basin. Our lease operating expenses were lower in 2013 as compared to 2012 by $1.7
million because of decreases of $1.0 million in elective costs such as well servicing and repairs and maintenance, $0.5 million in lower insurance, and $0.2 million in lower ad valorem taxes.
For the six months ended June 30, 2013, per unit lease operating expenses were $2.11 per Mcfe compared to $2.37 per Mcfe for
the same period in 2012.
For the six months ended June 30, 2013, production taxes increased $0.3 million, or 44.6%, to
$1.1 million, compared to expenses of $0.8 million for the same period in 2012. This increase is primarily the result of higher market prices for natural gas and oil in 2013 offset by the impact of production taxes on 0.3 Bcfe in lower production in
2013.
23
Cost of sales.
For the six months ended June 30, 2013, cost of sales increased
by $0.2 million, or 25.6%, to $0.8 million, compared to $0.6 million for the same period in 2012. This represents the cost of purchased natural gas in the Cherokee Basin and was impacted by lower production volumes and lower market prices for
natural gas in 2012, as these costs are tied to natural gas prices in the Mid-continent region.
General and administrative
expenses.
General and administrative expenses include the costs of our employees, related benefits, field office expenses, professional fees, and other costs not directly associated with field operations. General and administrative expenses
increased $0.6 million, or 8.0%, to $8.1 million for the six months ended June 30, 2013, as compared to $7.5 million for the same period in 2012. Our general and administrative expenses were higher in 2013 as compared to 2012 because of $1.0
million in severance costs, $0.4 million in higher labor and incentive compensation costs, offset by $0.8 million in lower professional services and consulting costs including the costs associated with the termination of our support services
agreement for revenue accounting services. Without the severance costs, our total reported general and administrative expenses for the six months ended June 30, 2013, would have been lower by approximately $0.2 million as compared to the same
period in 2012.
Our per unit costs were $2.11 per Mcfe for the six months ended June 30, 2013, as compared to $1.81 per
Mcfe for the same period in 2012. This increase is attributable to the impact of 0.3 Bcfe in lower production and by an increase in total spending of approximately $0.6 million. Excluding the impact of the severance costs, our total per unit costs
excluding non-cash unit-based compensation expenses would have been $1.89 per Mcfe in 2013.
Gain on sale of asset.
Our
gain on the sale of assets increased approximately $0.02 million to a gain of less than $0.02 million for the six months ended June 30, 2013, as compared to none for the same period in 2012. In 2013, we sold trucks and surplus equipment in
Oklahoma at a gain of approximately $0.02 million.
Depreciation, depletion and amortization expense and Asset
Impairments.
Depreciation, depletion and amortization expenses include the depreciation, depletion and amortization of acquisition costs and equipment costs. Depletion is calculated using units-of-production under the successful efforts method
of accounting. Assuming everything else remains unchanged, as oil or natural gas production changes, depletion would change in the same direction.
Our depreciation, depletion and amortization expense for the six months ended June 30, 2013 was $9.6 million, or $2.48 per Mcfe, compared to $4.7 million, or $1.13 per Mcfe, for the same period in
2012. This increase in 2013 depreciation, depletion, and amortization reflects the decrease in our reserve base at December 31, 2012, primarily due to the impact of a lower SEC-required natural gas price used to calculate our reserves which
resulted in negative reserve revisions, and increased expenditures incurred for our drilling programs in 2012. These revisions were partially offset by increased oil reserves as a result of our successful drilling programs and a 0.3 Bcfe decrease in
production volumes during 2013 as compared to 2012. Our other assets are depreciated using the straight-line basis. Consistent with our prior practice, we will use our 2012 reserve report to calculate our depletion rate during the first three
quarters of 2013 and will use our 2013 reserve report to record our depletion in the fourth quarter of 2013.
For the six
months ended June 30, 2013, no asset impairment was recorded, compared to asset impairments of $0.1 million for the same period in 2012. Our non-cash impairment charges in 2012 were approximately $0.1 million to impair certain of our wells in
the Woodford Shale. This impairment was recorded because the net capitalized costs of the properties exceeded the fair value of the properties as measured by estimated cash flows reported in a third party reserve report. The impairment was primarily
caused by the impact of lower future natural gas prices during the first quarter of 2012 on future expected cash flows.
Interest expense.
Interest expense for the six months ended June 30, 2013 decreased $0.8 million, or 27.5%, to $2.2 million
as compared to $3.0 million in interest expense for the same period in 2012. This decrease was primarily due to $3.0 million in higher non-cash mark-to-market gains on our interest rate swaps that are accounted for as mark-to-market activities,
lower market interest expense of $0.3 million and higher interest rate swap settlements of $2.4 million, while capitalized interest remained flat in 2013 to the same period in 2012. At June 30, 2013, we had an outstanding balance under our
reserve-based credit facility of $34.0 million as compared to $88.4 million at June 30, 2012. The average interest rate on our outstanding debt was approximately 3.192% as of June 30, 2013 compared to 6.0% in 2012. We have used interest
rate swaps to reduce our exposure to changes in the LIBOR rate. In March 2013, we reduced our outstanding interest rate swaps that fix our LIBOR rate through 2014 to $30 million, which increased our interest rate swap settlements by $2.1 million.
This position was closed in May 2013 resulting in an offsetting non-cash gain in our mark-to-market interest swap activities. We accelerated the amortization of approximately $0.7 million in debt issue costs in 2013 as a result of the second
amendment of our reserve-based credit facility which set our borrowing base at $55.0 million effective with the sale of the Robinsons Bend Field assets.
Interest income.
Interest income for the six months ended June 30, 2013, was less than $0.01 million as compared to less than $0.01 million for the same period in 2012. During 2013, market
rates for overnight investments continued to be at historical lows, resulting in no significant earnings on our cash balances.
24
Discontinued Operations.
A loss from discontinued operations for the six months ended
June 30, 2013 increased $0.6 million, or 26.0%, to a loss of $2.7 million as compared to a loss of $2.1 million in discontinued operations for the same period in 2012. Our discontinued operations represent the net loss associated with the sale
of our Robinsons Bend Field assets in the Black Warrior Basin of Alabama, in a transaction that closed on February 28, 2013, with an effective date of December 1, 2012. The loss in 2013 reflects a $3.1 million loss on the sale of the
properties, only two months of income and lower depreciation expenses.
Liquidity and Capital Resources
During 2012 and through August 14, 2013, we utilized our cash flow from operations as our primary source of capital
to fund our operating and capital programs. Our primary use of capital during this time was for the development of existing oil opportunities within our asset base in the Cherokee Basin. On February 28, 2013, we also sold our Robinsons Bend
Field assets in the Black Warrior Basin of Alabama and used $50.0 million of the proceeds from that sale to reduce our outstanding debt. On August 9, 2013 we acquired oil, natural gas and natural gas liquids assets in Texas and Louisiana from SEP I
for a purchase price of $30.4 million. The cash portion of the transaction was financed with cash on hand and a borrowing of $16.7 million under CEPs reserve-based credit facility.
Based upon our current business plan for 2013, we anticipate that we will continue to generate sufficient operating cash flows to meet
our working capital needs and fund a planned capital expenditure program between $19.0 million and $21.0 million. We will be monitoring the capital resources available to us to meet our future financial obligations and our planned 2013 capital
expenditures. Our current expectation is that we will continue managing our business to operate within the cash flows that are generated.
Given our focus on debt reduction since June 2009, our quarterly distributions to our unitholders remained suspended through the second quarter of 2013. At June 30, 2013, we were restricted from
paying distributions to unitholders as we had no available cash (taking into account the cash reserves set by our board of managers for the proper conduct of our business and the payment of fees and expenses) from which to pay distributions.
Our future success in growing reserves and production will be highly dependent on the capital resources available to us and
our success in drilling for or acquiring additional reserves and managing the costs associated with our operations. We routinely monitor and adjust our capital expenditures and operating expenses in response to changes in oil and natural gas prices,
drilling and acquisition costs, industry conditions, availability of funds under our reserve-based credit facility, and internally generated cash flow. Based upon current oil and natural gas price expectations, our existing hedge position and
expected production levels in 2013, we anticipate that our cash flow from operations can meet our planned capital expenditures and other cash requirements for the next twelve months without increasing our debt. If needed, we may issue additional
equity securities to raise additional capital. Future cash flows and our borrowing capacity are subject to a number of variables, including the level of oil and natural gas production, the market prices for those products and our hedge position.
There can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain our reduced debt level, planned levels of capital expenditures, operating expenses, or any cash distributions that we may make
to unitholders.
Sources of Debt and Equity Financing
In May 2013, we amended our existing reserve-based credit facility. This amendment increased our borrowing capacity, extended the maturity
date and changed the lenders participating in the facility.
As of August 14, 2013, the borrowing base under our
reserve-based credit facility was $55.0 million and we had $50.7 million of debt outstanding under the facility, leaving us with $4.3 million in unused borrowing capacity. Our reserve-based credit facility matures on May 30, 2017.
In 2011, we filed a shelf registration statement with the SEC to register up to $500 million of debt or equity securities to repay or
refinance outstanding debt and to fund working capital, capital expenditures and any acquisitions. This registration statement will expire in February 2014. As a smaller reporting company, any sales of securities under our shelf registration
statement during the preceding rolling 12 months is limited to one-third of our public float. Our public float is calculated by multiplying the highest closing price of our Class B common units within the last 60 days by the number of outstanding
Class B common units held by non-affiliates. There is no guarantee that securities can or will be issued under the registration statement or that conditions in the financial markets would be supportive of an issuance of such securities by us. If
needed, we may also issue securities in one or more private placements.
Cash Flow from Operations
Our net cash flow provided by operating activities for the six months ended June 30, 2013 was $6.0 million, compared to net cash flow
provided by operating activities of $5.4 million for the same period in 2012. This $0.6 million increase in operating cash flow is attributable to the impact of $0.8 million from higher cash operating expenses, $0.2 million in lower cash flow from
discontinued operations, and changes in working capital.
The increase in oil and natural gas sales is a result of $6.0
million from higher market prices for natural gas and oil, offset by $5.6 million as a result of lower cash settlements of our oil and natural gas hedges and $1.1 million from lower natural gas production volumes offset by higher oil production
volumes. The lower cash operating expenses is primarily as a result of lower total spending for lease operating expenses offset by the impact of higher production taxes and higher cost of sales. The remaining net change in working capital and other
items is primarily the result of the timing of payments and collection of accounts receivable.
25
The change in our working capital from 2013 to 2012 was attributable to higher other assets
of $1.1 million, lower accrued liabilities of $1.4 million, and higher prepaid expenses of $0.1 million, offset by higher accounts receivable of $1.2 million and increased other liabilities of $1.1 million. Our accrued liabilities decreased after
the payments associated with our 2012 incentive compensation programs were made, offset by an increase in severance payments not yet made. Our accounts payable decreased due to timing of invoice payments and lower checks-in-transit in 2013. Our
receivables balance decreased as we collected additional oil sales from certain tank batteries and our royalty payable balance decreased due to both lower production volumes for our estimated oil and natural gas sales and royalty payments made on
oil sales. The increase in other assets is related to the establishment of an escrow account of approximately $1.2 million related to certain closing conditions associated with the sale of our Robinsons Bend Field assets in the Black Warrior
Basin of Alabama. These funds will be held in escrow for up to twenty-four months. Our discontinued operations had an effective date of the sale of December 1, 2012 and a closing date of February 28, 2013.
Our cash flow from operations is subject to many variables, the most significant of which are the volatility of market prices for oil and
natural gas, our hedging program and our level of production of oil and natural gas. Our future cash flow from operations will depend on our ability to maintain and increase production through our development program or completing acquisitions and
successfully executing our hedging program. For additional information on our business plan, refer to
Outlook
.
Open Commodity Hedge Position
We enter into hedging arrangements to reduce the impact of oil and natural gas price volatility on our operations. By removing the price volatility from a significant portion of our oil and natural gas
production, we have mitigated, but not eliminated, the potential effects of changing prices on our cash flow from operations for those periods. While mitigating the negative effects of falling commodity prices, these derivative contracts also limit
the benefits we might otherwise receive from increases in commodity prices. These derivative contracts also limit our ability to have additional cash flows to fund higher severance taxes, which are usually based on market prices for oil and natural
gas. Our operating cash flows are also impacted by the cost of oilfield services. In the event of inflation increasing service costs or administrative expenses, our hedging program will limit our ability to have increased operating cash flows to
fund these higher costs. Increases in the market prices for oil and natural gas will also increase our need for working capital as our commodity hedging contracts cash settle prior to our receipt of cash from our sales of the related commodities to
third parties.
It is our policy to enter into derivative contracts only with counterparties that are creditworthy financial
institutions deemed by management as competent and competitive market makers. Each of the counterparties to our derivative contracts is a lender in our reserve-based credit facility and we do not currently post collateral with our counterparties
under any of these agreements. This is significant since we are able to lock in sales prices on a substantial amount of our expected future production without posting cash collateral based on price changes prior to the hedges being cash settled.
For 2013, we now forecast our total net natural gas production to range between 7.1 Bcf and 7.9 Bcfe and our total net oil
production of between 220,000 Bbls and 250,000 Bbls. This forecast includes the contribution anticipated from the assets we acquired from SEP I in a transaction that closed in August 2013. For the remainder of 2013, the company has hedged
approximately 3.4 Bcfe of its natural gas production at an effective NYMEX fixed price of $6.17 per Mcfe with Mid-Continent basis hedges on 2.5 Bcfe of this amount at an average differential of $0.39 per Mcfe. The company also has hedges in place on
approximately 91 MBbl of its oil production at a fixed price of $97.88 per barrel. These hedge positions lock in a significant portion of our expected revenues for 2013, although we are still exposed to increases or decreases in oil and natural gas
prices on any of our unhedged volumes.
The following tables summarize, for the periods indicated, our hedges currently in
place through December 31, 2016. All of these derivatives are accounted for as mark-to-market activities.
MTM Fixed
Price SwapsNYMEX (Henry Hub)
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For the quarter ended (in MMBtu)
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March 31,
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June 30,
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Sept 30,
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Dec 31,
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Total
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Volume
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Average
Price
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Volume
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Average
Price
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Volume
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Average
Price
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Volume
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Average
Price
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Volume
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Average
Price
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2013
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1,721,278
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$
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6.17
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1,691,540
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$
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6.18
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3,412,818
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$
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6.18
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2014
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1,575,000
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$
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5.75
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1,592,500
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$
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5.75
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1,610,000
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$
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5.75
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1,610,000
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$
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5.75
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6,387,500
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$
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5.75
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2015
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1,011,055
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$
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4.27
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971,604
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$
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4.27
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938,968
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$
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4.27
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908,492
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$
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4.27
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3,830,119
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$
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4.27
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2016
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441,492
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$
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4.31
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426,825
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$
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4.31
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414,329
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$
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4.31
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403,684
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$
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4.31
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1,686,330
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$
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4.31
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15,316,767
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|
|
|
|
|
|
|
|
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|
|
|
|
|
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|
26
MTM Fixed Price Basis Swaps CenterPoint Energy Gas Transmission (East), ONEOK Gas Transportation
(Oklahoma), or Southern Star Central Gas Pipeline (Texas, Oklahoma, and Kansas)
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the quarter ended (in MMBtu)
|
|
|
|
March 31,
|
|
|
June 30,
|
|
|
Sept 30,
|
|
|
Dec 31,
|
|
|
Total
|
|
|
|
Volume
|
|
|
Weighted
Average $
|
|
|
Volume
|
|
|
Weighted
Average $
|
|
|
Volume
|
|
|
Weighted
Average $
|
|
|
Volume
|
|
|
Weighted
Average $
|
|
|
Volume
|
|
|
Weighted
Average $
|
|
2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,273,525
|
|
|
$
|
0.39
|
|
|
|
1,223,985
|
|
|
$
|
0.39
|
|
|
|
2,497,510
|
|
|
$
|
0.39
|
|
2014
|
|
|
1,178,422
|
|
|
$
|
0.39
|
|
|
|
1,133,022
|
|
|
$
|
0.39
|
|
|
|
1,084,270
|
|
|
$
|
0.39
|
|
|
|
1,047,963
|
|
|
$
|
0.39
|
|
|
|
4,443,677
|
|
|
$
|
0.39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,941,187
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MTM Fixed Price Basis SwapsWest Texas Intermediate (WTI)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the quarter ended (in Bbls)
|
|
|
|
March 31,
|
|
|
June 30,
|
|
|
Sept 30,
|
|
|
Dec 31,
|
|
|
Total
|
|
|
|
Volume
|
|
|
Average
Price
|
|
|
Volume
|
|
|
Average
Price
|
|
|
Volume
|
|
|
Average
Price
|
|
|
Volume
|
|
|
Average
Price
|
|
|
Volume
|
|
|
Average
Price
|
|
2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
44,490
|
|
|
$
|
97.60
|
|
|
|
46,079
|
|
|
$
|
98.15
|
|
|
|
90,569
|
|
|
$
|
97.88
|
|
2014
|
|
|
43,353
|
|
|
$
|
94.04
|
|
|
|
40,991
|
|
|
$
|
94.10
|
|
|
|
38,874
|
|
|
$
|
94.18
|
|
|
|
36,811
|
|
|
$
|
94.30
|
|
|
|
160,029
|
|
|
$
|
94.15
|
|
2015
|
|
|
23,919
|
|
|
$
|
93.37
|
|
|
|
22,494
|
|
|
$
|
93.48
|
|
|
|
21,237
|
|
|
$
|
93.58
|
|
|
|
20,030
|
|
|
$
|
93.70
|
|
|
|
87,680
|
|
|
$
|
93.53
|
|
2016
|
|
|
17,957
|
|
|
$
|
85.50
|
|
|
|
16,985
|
|
|
$
|
85.50
|
|
|
|
16,048
|
|
|
$
|
85.50
|
|
|
|
15,127
|
|
|
$
|
85.50
|
|
|
|
66,117
|
|
|
$
|
85.50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
404,395
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing ActivitiesAcquisitions and Capital Expenditures
Cash provided by investing activities was $52.6 million for the six months ended June 30, 2013, compared to cash used in investing
activities of $5.3 million for the same period in 2012. Our cash capital expenditures were $6.4 million in 2013, which consisted of $6.3 million in development expenditures in the Cherokee Basin and $0.1 million to acquire certain additional natural
gas wells in the Cherokee Basin. We have completed 26 net wells and 13 net recompletions during the first six months of 2013 and have 5 net wells and net recompletions in progress at June 30, 2013. We also sold our Robinsons Bend Field
assets in the Black Warrior Basin of Alabama for net proceeds of approximately $58.9 million after customary costs and working capital adjustments and received less than $0.1 million in distributions from an equity affiliate. We do not currently
expect the sale of our natural gas assets in the Black Warrior Basin of Alabama to significantly reduce our future net cash flows in 2013, as we have significantly reduced our outstanding debt level which will lower our cash interest payments.
Our cash capital expenditures were $6.8 million for the six months ended June 30, 2012, which primarily consisted of
development expenditures in the Cherokee Basin. We completed 21 net wells and 27 net recompletions during the first six months of 2012 and had 24 net wells and net recompletions in progress. We also sold 14 wells in the Central Kansas Uplift for
$1.4 million and $0.1 million in trucks and equipment during the first half of 2012 and received approximately $0.1 million in distributions from an equity affiliate.
Our current 2013 capital budget of $19.0 million to $21.0 million remains unchanged and is expected to be funded using our cash flow from operations and by using the remaining net proceeds from the sale
of our natural gas assets in the Black Warrior Basin. We currently expect to focus our entire 2013 capital budget on higher return oil opportunities and capital efficient recompletion opportunities in our existing asset base in the Cherokee Basin.
We currently believe that opportunity set is sufficient to warrant a continuing focus on our oil opportunities in the Cherokee Basin with investment of free cash flow at rates of return exceeding 20% over the next few years.
The amount and timing of our capital expenditures is largely discretionary and within our control. If oil or natural gas prices decline
to levels below acceptable levels, drilling costs escalate, or our efforts to exploit oil potential in our asset base prove to be unsuccessful, we could choose to defer a portion of these planned capital expenditures until later periods. We
routinely monitor and adjust our capital expenditures in response to changes in oil and natural gas prices, drilling and acquisition costs, industry conditions, availability of funds under our reserve-based credit facility, and internally generated
cash flow. These and other matters are outside of our control and could affect the timing of our capital expenditures. Based upon current oil and natural gas price expectations and expected 2013 production levels, we anticipate that our cash flow
from operations will meet any planned capital expenditures and other cash requirements for the next twelve months. We also have access to any existing available borrowing capacity under our reserve-based credit facility and our then existing cash
balance if additional funds are needed in the future. Future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices. There can be no assurance that our operations and other capital resources
will provide cash in sufficient amounts during 2013 to maintain our planned levels of capital expenditures, to maintain the outstanding debt level under our reserve-based credit facility, or to commence any quarterly distribution to unitholders. Our
capital expenditures are also impacted by drilling and service costs. In the event of inflation increasing drilling and service costs, our hedging program will limit our ability to have increased revenues recoup the higher costs, which could further
impact our planned capital spending.
27
Financing Activities
Our net cash used by financing activities was $51.0 million for the six months ended June 30, 2013, compared to $10.2 million used by financing activities for the same period in 2012. In 2013, we
borrowed $0.2 million in short-term borrowings under our reserve-based credit facility for working capital purposes. During the first six months of 2013, we used $50.2 million to reduce our outstanding debt level to $34.0 million. This debt
reduction was funded from the proceeds from the sale of our Robinsons Bend Field assets in the Black Warrior Basin of Alabama. We also used $0.2 million to fund the cost of units tendered by employees for tax withholdings for unit-based
compensation. At June 30, 2013, we had approximately $0.8 million in debt issue costs remaining to be amortized over the life our reserve-based credit facility.
We suspended our $0.13 per unit quarterly distributions to unitholders for the quarter ended June 30, 2009, through the quarter ended June 30, 2013, to reduce our outstanding indebtedness.
Our net cash used by financing activities was $10.2 million for the six months ended June 30, 2012. We used $0.2 million
to fund the cost of units tendered by employees for tax withholdings for unit-based compensation and had approximately $1.8 million in debt issue costs remaining to be amortized at June 30, 2012.
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements with third parties, and we maintain no debt obligations that contain provisions requiring accelerated payment of the related obligations in the event of specified
levels of declines in credit ratings.
Credit Markets and Counterparty Risk
We actively monitor the credit exposure and risks associated with our counterparties. Additionally, we continue to monitor global credit
markets to limit our potential exposure to credit risk where possible. Our primary credit exposures result from the sale of oil and natural gas and our use of derivatives. Through August 14, 2013, we have not suffered any significant losses
with our counterparties as a result of nonperformance.
Certain key counterparty relationships are described below:
Macquarie Energy LLC
Macquarie Energy LLC (Macquarie), a subsidiary of Sydney, Australia-based Macquarie Group Limited, purchases a portion of our natural gas production in the Cherokee Basin. We have received a
guarantee from Macquarie Bank Limited for up to $4.0 million in purchases through December 31, 2013. As of August 14, 2013, we have no past due receivables from Macquarie.
Scissortail Energy, LLC
Scissortail Energy, LLC (Scissortail), a subsidiary of Copano Energy, L.L.C., purchases a portion of our natural gas production in Oklahoma and Kansas. As of August 14, 2013, we have no
past due receivables from Scissortail.
ONEOK Energy Services Company, L.P.
ONEOK Energy Services Company, L.P. (ONEOK), a subsidiary of ONEOK, Inc., purchases a portion of our natural gas production in
Oklahoma and Kansas. We have received a guarantee from ONEOK, Inc. for up to $3.0 million in purchases through November 30, 2013. As of August 14, 2013, we have no past due receivables from ONEOK.
Derivative Counterparties
As of August 14, 2013, all of our derivatives are with Societe Generale and The Bank of Nova Scotia. All of our derivatives are currently collateralized by the assets securing our reserve-based
credit facility and therefore currently do not require the posting of cash collateral. As of August 14, 2013, each of these financial institutions has an investment grade credit rating.
Reserve-Based Credit Facility
As of August 14, 2013, the banks and their percentage commitments in our reserve-based credit facility are: Societe Generale (36.36%), OneWest Bank, FSB (36.36%), and BOKF NA, dba Bank of Oklahoma
(27.28%). As of August 14, 2013, each of these financial institutions has an investment grade credit rating.
28
Outlook
During 2013, we expect that our business will continue to be affected by the factors described in Item 1A. Risk Factors of our Annual Report on Form 10-K for the year ended
December 31, 2012, as well as the following key industry and economic trends. Our expectation is based upon key assumptions and information currently available to us. To the extent that our underlying assumptions about or interpretations of
available information prove to be incorrect, our actual results may vary materially from our expected results.
Full Year
2013 Expected Results
Our 2013 business plan and forecast is focused on prioritizing oil production in the execution of
our capital program, actively managing our operating expenses and actively pursuing merger and acquisition opportunities. We currently expect our operating environment to be characterized by continued low natural gas prices, stable oil prices and
the pressure to reduce operating expenses.
For 2013, we currently anticipate:
|
|
|
Our production to be at or slightly below 8.9 Bcfe and we are significantly hedged at prices that are attractive relative to the price levels we
currently observe in the commodity markets.
|
|
|
|
Our operating expenses to be actively managed, resulting in a range of $32.5 million to $35.3 million.
|
|
|
|
Our Adjusted EBITDA to be in a range of $27.5 million to $29.5 million.
|
|
|
|
Our total capital expenditures to be between $19.0 million to $21.0 million.
|
|
|
|
We have implemented strategies to lower operating costs, with a goal of reducing our structural general and administrative costs by the end of 2013. We
expect our general and administrative expenses to have a run rate of $12.4 million in 2013, with opportunities available to save another $0.6 million in 2014.
|
|
|
|
At the present time, we are actively pursuing merger and acquisition opportunities.
|
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles
generally accepted in the United States of America. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of
contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if
different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions. The results of these estimates and assumptions form the basis for making
judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in the preparation of our financial statements.
As of June 30, 2013, there were no changes with regard to the critical accounting policies disclosed in our Annual Report on Form
10-K for the year ended December 31, 2012, which was filed on March 11, 2013. The policies disclosed included the accounting for oil and natural gas properties, oil and natural gas reserve quantities, revenue recognition and hedging
activities. Please read Note 1 to the consolidated financial statements for a discussion of additional accounting policies and estimates made by management.
New Accounting Pronouncements Issued But Not Yet Adopted
As of
June 30, 2013, there were a number of accounting standards and interpretations that had been issued, but not yet adopted by us. We are currently reviewing the recently issued standards and interpretations but none are expected to have a
material impact on our financial statements.
New Accounting Pronouncements
See Note 1 to our condensed consolidated financial statements included in this report for information on new accounting pronouncements.