This prospectus
supplement is being filed to update and supplement information contained in the prospectus dated May 11, 2017 with information contained in our Quarterly Report on Form
10-Q
for the quarter ended
September 30, 2017, filed with the Securities and Exchange Commission (the “SEC”) on November 28, 2017.
This
prospectus supplement updates and supplements the information in the prospectus and is not complete without, and may not be delivered or utilized except in combination with, the prospectus, including any other amendments or supplements thereto. This
prospectus supplement should be read in conjunction with the prospectus and if there is any inconsistency between the information in the prospectus and this prospectus supplement, you should rely on the information in this prospectus supplement.
Indicate by check mark whether
the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports),
and (2) has been subject to such filing requirements for the past 90 days. Yes
☒
No
☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required
to be submitted and posted pursuant to Rule 405 of Regulation
S-T
during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such
files). Yes
☒
No
☐
Indicate by
check mark whether the registrant is a large accelerated filer, an accelerated filer, a
non-accelerated
filer, smaller reporting company, or an emerging growth company. See definitions of “large
accelerated filer”, “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule
12b-2
of the Exchange Act.
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period
for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule
12b-2
of the Exchange
Act). Yes
☐
No
☒
Indicate by
check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a
court. Yes ☒ No ☐
The number of outstanding common shares of the
registrant on November 27, 2017 was 5,444,794.
Successor’s Management Incentive Plan
Pursuant to the Titan Energy, LLC Management Incentive Plan (the “MIP”) plan, participants are allowed to withhold or surrender
shares for the payment of taxes. These shares are available for
re-issuance
under the MIP. For the three months ended September 30, 2017, 91,710 shares under the MIP became unrestricted. Of these shares,
42,251 were withheld for taxes, which resulted in $0.2 million recognized in our consolidated statement of changes in members’ equity. For the nine months ended
14
September 30, 2017, 91,710 shares under the MIP became unrestricted and 37,324 shares were granted and vested immediately. Of these shares, 57,562 were withheld for taxes, which resulted in
$0.3 million recognized in our consolidated statement of changes in members’ equity. For the Successor period September 1, 2016 through September 30, 2016, 138,750 shares were granted and vested immediately.
Predecessor’s 2012 Long-Term Incentive Plan
On May 12, 2016, due to the income tax ramifications of the potential options our Predecessor was considering, our Predecessor’s
Board of Directors delayed the vesting date of approximately 110,000 units granted to employees, directors and officers until March 2017. The phantom units were set to vest between May 15, 2016 and August 31, 2016. The delayed vesting
schedule did not have a significant impact on the compensation expense recorded in general and administrative expenses on the condensed consolidated statement of operations for the Predecessor period from January 1, 2016 through August 31,
2016 or our Predecessor’s remaining unrecognized compensation expense related to such awards. As a result of the Chapter 11 Filings, our Predecessor’s 2012 LTIP phantom units were cancelled. The remaining unrecognized compensation cost of
$0.8 million was recognized upon the cancellation and was recorded in general and administrative expenses on the condensed consolidated statement of operations for the Predecessor period from July 1, 2016 through August 31, 2016.
Successor’s Net Income Attributable to Common Shareholders Per Share
The Successor’s basic net income attributable to common shareholders per share is computed by dividing net income attributable to our
common shareholders by the weighted-average number of common shares outstanding, excluding any unvested restricted shares, for the period. The Successor’s diluted net income attributable to common shareholders per share is similarly calculated
except that the common shares outstanding for the period are increased using the treasury stock method to reflect the potential dilution that could occur if outstanding share based awards were vested at the end of the applicable period.
Anti-dilutive shares represent potentially dilutive securities that are excluded from the computation of diluted net income attributable to common shareholders per share as their impact would be anti-dilutive. We determine if potentially dilutive
shares are anti-dilutive based on their impact to net income (loss) from continuing operations.
15
The following is a reconciliation of net income attributable to our Successor’s common
shareholders for purposes of calculating net income attributable to our Successor’s common shareholders per share (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
Three Months
Ended
September 30,
2017
|
|
|
Nine Months
Ended
September 30,
2017
|
|
|
Period from
September 1,
2016 through
September 30,
2016
|
|
|
Net loss from continuing operations
|
|
$
|
(19,706
|
)
|
|
$
|
(15,084
|
)
|
|
$
|
(7,364
|
)
|
|
Less: Series A Preferred member interest in loss from continuing operations
|
|
|
(394
|
)
|
|
|
(302
|
)
|
|
|
(147
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss from continuing operations utilized in the calculation of net loss attributable to common
shareholders per share
|
|
$
|
(19,312
|
)
|
|
$
|
(14,782
|
)
|
|
$
|
(7,217
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) from discontinued operations
|
|
$
|
2,156
|
|
|
$
|
20,945
|
|
|
$
|
(167
|
)
|
|
Less: Series A Preferred member interest in net income (loss) from discontinued
operations
|
|
|
43
|
|
|
|
419
|
|
|
|
(4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) from discontinued operations utilized in the calculation of net income (loss)
attributable to common shareholders per share
|
|
$
|
2,113
|
|
|
$
|
20,526
|
|
|
$
|
(163
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table is a reconciliation of the Successor’s basic and diluted weighted average number of
common shares used to calculate basic and diluted net income attributable to common shareholders per share (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
Three Months
Ended
September 30,
2017
|
|
|
Nine Months
Ended
September 30,
2017
|
|
|
Period from
September 1,
2016 through
September 30,
2016
|
|
|
Weighted average number of common shares - basic
(1)
|
|
|
5,208
|
|
|
|
5,186
|
|
|
|
5,139
|
|
|
Add dilutive effect of share based awards at end of period
(2)
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares - diluted
|
|
|
5,208
|
|
|
|
5,186
|
|
|
|
5,139
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
For the three and nine months ended September 30, 2017, 186,000 and 278,000 restricted common shares outstanding, respectively, were excluded from the calculation of basic weighted average number of common shares
because they were not vested. For the Successor period from September 1, 2016 through September 30, 2016, 278,000 restricted common shares outstanding were excluded from the calculation of basic weighted average number of common shares
because they were not vested.
|
|
(2)
|
We determine if potentially dilutive shares are anti-dilutive based on their impact to net income (loss) from continuing operations. Since all of the periods presented resulted in net loss from continuing operations
attributable to common shareholders, potentially dilutive shares were excluded because their inclusion would have been anti-dilutive.
|
16
Predecessor’s Net Income (Loss) Per Common Unit
The following is a reconciliation of net income (loss) allocated to our Predecessor’s common limited partners for purposes of calculating
net income (loss) attributable to our Predecessor’s common limited partners per unit (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
|
|
Period From
July 1 through
August 31,
2016
|
|
|
Period From
January 1
through
August 31,
2016
|
|
|
Net loss from continuing operations
|
|
$
|
(36,772
|
)
|
|
$
|
(147,239
|
)
|
|
Preferred limited partner dividends
|
|
|
—
|
|
|
|
(4,013
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net loss from continuing operations attributable to common limited partners and the general
partner
|
|
|
(36,772
|
)
|
|
|
(151,252
|
)
|
|
Less: General partner’s interest in net loss from continuing operations
|
|
|
(736
|
)
|
|
|
(3,025
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net loss from continuing operations attributable to common limited partners
|
|
|
(36,036
|
)
|
|
|
(148,227
|
)
|
|
Less: Net income from continuing operations attributable to participating securities –
phantom units
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss from continuing operations utilized in the calculation of net loss attributable to common
limited partners per unit – Basic
|
|
|
(36,036
|
)
|
|
|
(148,227
|
)
|
|
Plus: Convertible preferred limited partner
dividends
(1)
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss from continuing operations utilized in the calculation of net loss attributable to common
limited partners per unit – Diluted
|
|
$
|
(36,036
|
)
|
|
$
|
(148,227
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net loss from discontinued operations attributable to common limited partners and the general
partner
|
|
$
|
(11,852
|
)
|
|
$
|
(30,191
|
)
|
|
Less: General partner’s interest in net loss from discontinued operations
|
|
|
(237
|
)
|
|
|
(604
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net loss from discontinued operations attributable to common limited partners
|
|
|
(11,615
|
)
|
|
|
(29,587
|
)
|
|
Less: Net income from discontinued operations attributable to participating securities –
phantom units
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss from discontinued operations utilized in the calculation of net loss attributable to
common limited partners per unit – Basic
|
|
|
(11,615
|
)
|
|
|
(29,587
|
)
|
|
Plus: Convertible preferred limited partner
dividends
(1)
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss from discontinued operations utilized in the calculation of net loss attributable to
common limited partners per unit – Diluted
|
|
$
|
(11,615
|
)
|
|
$
|
(29,587
|
)
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
For the periods presented, distributions on our Predecessor’s Class C convertible preferred units were excluded, because the inclusion of such preferred distributions would have been anti-dilutive.
|
17
The following table sets forth the reconciliation of our Predecessor’s weighted average
number of common limited partner units used to compute basic net income (loss) attributable to our Predecessor’s common limited partners per unit with those used to compute diluted net income attributable to our Predecessor’s common
limited partners per unit (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
|
|
Period From
July 1
through
August 31,
2016
|
|
|
Period From
January 1
through
August 31,
2016
|
|
|
Weighted average number of common limited partner units—basic
|
|
|
104,366
|
|
|
|
102,912
|
|
|
Add effect of dilutive incentive
awards
(1)
|
|
|
—
|
|
|
|
—
|
|
|
Add effect of dilutive convertible preferred limited partner units
(2)
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common limited partner units—diluted
|
|
|
104,366
|
|
|
|
102,912
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
For the Predecessor periods from July 1, 2016 through August 31, 2016 and from January 1, 2016 through August 31, 2016, 247,000 and 274,000 phantom units, respectively, were excluded from the
computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive.
|
|
(2)
|
For the periods presented, potential common limited partner units issuable upon (a) conversion of our Predecessor’s Class C preferred units and (b) exercise of the common unit warrants issued with
our Predecessor’s Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive. As our Predecessor’s
Class D and Class E preferred units were convertible only upon a change of control event, they were not considered dilutive securities for earnings per unit purposes.
|
Recently Issued Accounting Standards
In
February 2016, the FASB updated the accounting guidance related to leases. The updated accounting guidance requires lessees to recognize a lease asset and liability at the commencement date of all leases (with the exception of short-term leases),
initially measured at the present value of the lease payments. The updated guidance is effective for us as of January 1, 2019 and requires a modified retrospective transition approach for leases existing at, or entered into after, the beginning
of the earliest period presented. We are currently in the process of determining the impact that the updated accounting guidance will have on our condensed consolidated financial statements.
In May 2014, the FASB updated the accounting guidance related to revenue recognition. The updated accounting guidance provides a single,
contract-based revenue recognition model to help improve financial reporting by providing clearer guidance on when an entity should recognize revenue, and by reducing the number of standards to which an entity has to refer. In July 2015, the FASB
voted to defer the effective date by one year to December 15, 2017 for annual reporting periods beginning after that date. We have made progress on our contract reviews and documentation. Substantially all of our revenue is earned pursuant to
agreements under which we have currently interpreted one performance obligation, which is satisfied at a
point-in-time.
We are currently unable to reasonably estimate
the expected financial statement impact; however, we do not believe the new accounting guidance will have a material impact on our financial position, results of operations or cash flows. We intend to adopt the new accounting guidance using the
modified retrospective method. The new accounting guidance will require that our revenue recognition policy disclosures include further detail regarding our performance obligations as to the nature, amount, timing, and estimates of revenue and cash
flows generated from our contracts with customers.
NOTE 3 – DISCONTINUED OPERATIONS AND DIVESTITURES
Appalachia Divestiture – Discontinued Operations
As disclosed in Note 2, on June 30, 2017, we completed a majority of the Appalachian Assets sale for net cash proceeds of
$65.6 million, which included customary preliminary purchase price adjustments, all of which was used to repay a portion of the outstanding indebtedness under our First Lien Credit Facility. On September 29, 2017, we completed the
remainder of the Appalachian Assets sale for additional cash proceeds of $10.4 million, all of which was used to repay a portion of outstanding borrowings under our First Lien Credit Facility.
We determined the Appalachian Assets represent discontinued operations as they constitute a disposal of a group of components and a strategic
shift that will have a major effect on our operations and financial results. We evaluated the Appalachian Assets sale on our gas and oil production and Drilling Partnership management segments’ results of operations and cash flows, as well as
expected
18
asset retirement obligations, and concluded the impact will have a major effect on our expected operations and financial results. As a result, we reclassified the Appalachian Assets from their
historical presentation to assets and liabilities held for sale on the condensed consolidated balance sheet and to net income (loss) from discontinued operations on the condensed consolidated statement of operations for all periods presented.
We determined that the carrying value of the remainder of our Appalachian Assets exceeded the fair value less costs to sell, which resulted in
an impairment of $4.3 million recognized in net income (loss) from discontinued operations on our condensed consolidated statement of operations during the nine months ended September 30, 2017.
The following table reconciles the major classes of line items from the discontinued operations of the Appalachian Assets included within net
income (loss) from discontinued operations, in thousands:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
|
Predecessor
|
|
|
|
|
Three Months
Ended
September 30,
2017
|
|
|
Nine Months
Ended
September 30,
2017
|
|
|
Period From
September 1
to
September 30,
2016
|
|
|
|
|
|
|
Period From
July 1 to
August 31,
2016
|
|
|
Period
From
January 1 to
August 31,
2016
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas and oil production
|
|
$
|
288
|
|
|
$
|
21,213
|
|
|
$
|
1,197
|
|
|
|
|
|
|
$
|
2,917
|
|
|
$
|
10,037
|
|
|
Drilling partnership management
|
|
|
—
|
|
|
|
5,114
|
|
|
|
1,320
|
|
|
|
|
|
|
|
3,621
|
|
|
|
12,100
|
|
|
Gain (loss) on
mark-to-market
derivatives
|
|
|
—
|
|
|
|
4,955
|
|
|
|
750
|
|
|
|
|
|
|
|
875
|
|
|
|
(667
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
288
|
|
|
|
31,282
|
|
|
|
3,267
|
|
|
|
|
|
|
|
7,413
|
|
|
|
21,470
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas and oil production
|
|
$
|
924
|
|
|
$
|
9,091
|
|
|
$
|
760
|
|
|
|
|
|
|
$
|
1,454
|
|
|
$
|
6,244
|
|
|
Drilling partnership management
|
|
|
597
|
|
|
|
5,824
|
|
|
|
1,074
|
|
|
|
|
|
|
|
2,312
|
|
|
|
9,801
|
|
|
Depreciation, depletion and amortization
|
|
|
—
|
|
|
|
4,842
|
|
|
|
869
|
|
|
|
|
|
|
|
2,693
|
|
|
|
9,059
|
|
|
General and administrative
|
|
|
298
|
|
|
|
4,378
|
|
|
|
395
|
|
|
|
|
|
|
|
12,044
|
|
|
|
16,974
|
|
|
Gain on sale of assets
|
|
|
(4,319
|
)
|
|
|
(32,921
|
)
|
|
|
(4
|
)
|
|
|
|
|
|
|
(50
|
)
|
|
|
(72
|
)
|
|
Impairment on assets held for sale
|
|
|
—
|
|
|
|
4,272
|
|
|
|
—
|
|
|
|
|
|
|
|
—
|
|
|
|
—
|
|
|
Interest expense
|
|
|
115
|
|
|
|
2,769
|
|
|
|
340
|
|
|
|
|
|
|
|
842
|
|
|
|
3,529
|
|
|
Other (income) loss
|
|
|
541
|
|
|
|
541
|
|
|
|
—
|
|
|
|
|
|
|
|
(30
|
)
|
|
|
6,126
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
$
|
(1,844
|
)
|
|
$
|
(1,204
|
)
|
|
$
|
3,434
|
|
|
|
|
|
|
$
|
19,265
|
|
|
$
|
51,661
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from discontinued operations before income taxes
|
|
|
2,132
|
|
|
|
32,486
|
|
|
|
(167
|
)
|
|
|
|
|
|
|
(11,852
|
)
|
|
|
(30,191
|
)
|
|
Income tax provision (benefit)
|
|
|
(24
|
)
|
|
|
11,541
|
|
|
|
—
|
|
|
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) from discontinued operations
|
|
$
|
2,156
|
|
|
$
|
20,945
|
|
|
$
|
(167
|
)
|
|
|
|
|
|
$
|
(11,852
|
)
|
|
$
|
(30,191
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We allocated First Lien Credit Facility interest expense to our discontinued operations based on the relative
proportion of the net cash proceeds from the sale of the Appalachian Assets used to repay outstanding indebtedness under our First Lien Credit Facility to the total outstanding indebtedness under our First Lien Credit Facility for the periods
presented.
We allocated gain (loss) on
mark-to-market
natural gas commodity derivatives to our discontinued operations based on the relative proportion of the Appalachian Assets’ natural gas production volumes to our total natural gas production volumes for the periods presented.
19
The following table details the major classes of assets and liabilities of the Appalachian Assets
discontinued operations classified as held for sale for the prior period presented, in thousands:
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
2016
|
|
|
Current assets:
|
|
|
|
|
|
Accounts receivable
|
|
$
|
7,254
|
|
|
Prepaid expenses and other
|
|
|
1,017
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
8,271
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
|
113,956
|
|
|
Other assets
|
|
|
449
|
|
|
|
|
|
|
|
|
Total
non-current
assets
|
|
|
114,405
|
|
|
|
|
|
|
|
|
Total assets classified as held for sale
|
|
$
|
122,676
|
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
Accounts payable
|
|
$
|
2,516
|
|
|
Current portion of derivative liability
|
|
|
4,279
|
|
|
Accrued liabilities and other
|
|
|
2,666
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
9,461
|
|
|
|
|
|
|
|
|
Long-term derivative liability
|
|
|
1,407
|
|
|
Asset retirement obligations
|
|
|
60,316
|
|
|
Other long-term liabilities
|
|
|
682
|
|
|
|
|
|
|
|
|
Total
non-current
liabilities
|
|
|
62,405
|
|
|
|
|
|
|
|
|
Total liabilities classified as held for sale
|
|
$
|
71,866
|
|
|
|
|
|
|
|
We allocated natural gas commodity derivatives assets and liabilities to our discontinued operations held for
sale based on the relative proportion of the Appalachian Assets’ natural gas production volumes to our total natural gas production volumes as of December 31, 2016.
Rangely Divestiture
As disclosed in Note
2, on August 7, 2017, we completed the Rangely Assets sale for net cash proceeds of $103.5 million, which included customary preliminary purchase price adjustments, all of which was used to repay a portion of the outstanding indebtedness
under our First Lien Credit Facility. We determined that the carrying value of the Rangely Assets exceeded the fair value less costs to sell, which resulted in an impairment of $38.2 million recognized in loss on divesture on our condensed
consolidated statement of operations during the Successor nine months ended September 30, 2017. We recognized a $5.2 million loss on asset sale from the closing of the Rangely Assets sale during the Successor three and nine months ended
September 30, 2017 resulting from final negotiations and settlement of working capital adjustments in connection with the preliminary purchase price adjustments.
We considered the Rangely Assets to be an individually significant component of our operations. The following table presents the net income
(loss) before income taxes of the Rangely Assets for the periods presented, in thousands:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
|
Predecessor
|
|
|
|
|
Three Months
Ended
September 30,
2017
|
|
|
Nine Months
Ended
September 30,
2017
|
|
|
Period From
September 1
to September 30,
2016
|
|
|
|
|
|
|
Period From
July 1 to
August 31,
2016
|
|
|
Period From
January 1 to
August 31,
2016
|
|
|
Income (loss) before income taxes
(1)
|
|
$
|
(4,292
|
)
|
|
$
|
(38,379
|
)
|
|
$
|
532
|
|
|
|
|
|
|
$
|
1,253
|
|
|
$
|
2,011
|
|
|
(1)
|
Income (loss) before income taxes reflects gas and oil production revenues less gas and oil production expenses, general and administrative expenses, depletion, depreciation, and amortization expenses for all periods
presented. The Successor three and nine months ended September 30, 2017 include $5.2 million of loss on asset sale resulting from the closing of the Rangely Asset sale. The Successor nine months ended September 30, 2017 also includes
$38.2 million loss on divestiture resulting from the carrying value of the Rangely Assets exceeding the fair value less costs to sell as disclosed above.
|
20
NOTE 4 – PROPERTY, PLANT AND EQUIPMENT
The following is a summary of property, plant and equipment at the dates indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30,
2017
|
|
|
December 31,
2016
|
|
|
Natural gas and oil properties:
|
|
|
|
|
|
|
|
|
|
Proved properties
|
|
$
|
519,147
|
|
|
$
|
608,901
|
|
|
Unproved properties
|
|
|
52,767
|
|
|
|
73,057
|
|
|
Support equipment and other
|
|
|
8,690
|
|
|
|
8,081
|
|
|
|
|
|
|
|
|
|
|
|
|
Total natural gas and oil properties
|
|
|
580,604
|
|
|
|
690,039
|
|
|
Less – accumulated depreciation, depletion and amortization
|
|
|
(53,207
|
)
|
|
|
(19,270
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Total property, plant and equipment, net
|
|
$
|
527,397
|
|
|
$
|
670,769
|
|
|
|
|
|
|
|
|
|
|
|
During the Successor nine months ended September 30, 2017, the Successor period from September 1,
2016 through September 30, 2016 and the Predecessor period from January 1, 2016 through August 31, 2016, we recognized $0.7 million, $3.5 million and $19.6 million, respectively, of
non-cash
investing activities capital expenditures, which was reflected within the changes in accounts payable and accrued liabilities on our condensed consolidated statements of cash flows.
We capitalize interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects
to their intended use. The weighted average interest rate used to capitalize interest on borrowed funds during the Successor three and nine months ended September 30, 2017, the Successor period September 1, 2016 through September 30,
2016, and the Predecessor periods from July 1, 2016 through August 31, 2016 and January 1, 2016 through August 31, 2016 were 9.5%, 8.4%, 7.6%, 6.0% and 6.5%, respectively. The aggregate amount of interest capitalized during the
Successor three and nine months ended September 30, 2017, the Successor period September 1, 2016 through September 30, 2016, and the Predecessor periods from July 1, 2016 through August 31, 2016 and January 1, 2016
through August 31, 2016 were $0.2 million, $0.4 million, $0.7 million, $1.7 million and $6.5 million, respectively.
For the Successor three and nine months ended September 30, 2017, the Successor period September 1, 2016 through September 30,
2016, and the Predecessor periods from July 1, 2016 through August 31, 2016 and January 1, 2016 through August 31, 2016, we recorded $0.4 million, $1.1 million, $0.5 million, $1.3 million and
$4.6 million, respectively, of accretion expense related to our asset retirement obligations within depreciation, depletion and amortization in our condensed consolidated statements of operations.
NOTE 5 – DEBT
Total debt consists
of the following at the dates indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
|
December 31,
|
|
|
|
|
2017
|
|
|
2016
|
|
|
First Lien Credit Facility
|
|
$
|
256,273
|
|
|
$
|
435,809
|
|
|
Second Lien Credit Facility
|
|
|
283,523
|
|
|
|
261,022
|
|
|
Deferred financing costs, net of accumulated amortization of $686 and $172, respectively
|
|
|
(1,711
|
)
|
|
|
(2,021
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Total debt, net
|
|
|
538,085
|
|
|
|
694,810
|
|
|
Less current maturities
|
|
|
(538,085
|
)
|
|
|
(694,810
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt, net
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
Cash Interest
. Total cash payments for interest for the Successor three and nine months ended
September 30, 2017, the Successor period September 1, 2016 through September 30, 2016 and the Predecessor period from January 1, 2016 through August 31, 2016, were $7.3 million, $21.2 million, $0.5 million and
$53.7 million, respectively. There were no cash payments for interest for the Predecessor period from July 1, 2016 through August 31, 2016 due to our Predecessor’s Chapter 11 Filings.
21
First Lien Credit Facility
On September 1, 2016, we entered into our $440 million First Lien Credit Facility with Wells Fargo Bank, National Association
(“Wells Fargo”), as administrative agent, and the lenders party thereto. A summary of the key provisions of the First Lien Credit Facility is as follows (of which certain provisions have been modified through subsequent amendments as
described further below):
|
|
•
|
|
Borrowing base of a $410 million conforming reserve based tranche plus a $30 million
non-conforming
tranche.
|
|
|
•
|
|
Provides for the issuance of letters of credit, which reduce borrowing capacity.
|
|
|
•
|
|
Obligations are secured by mortgages on substantially all of our oil and gas properties and first priority security interests in substantially all of our assets and are guaranteed by certain of our material
subsidiaries, and any
non-guarantor
subsidiaries of ours are minor.
|
|
|
•
|
|
Borrowings bear interest at our election at either LIBOR plus an applicable margin between 3.00% and 4.00% per annum or the “alternate base rate” plus an applicable margin between 2.00% and 3.00% per annum,
which fluctuates based on utilization. We are also required to pay a fee of 0.50% per annum on the unused portion of the borrowing base. At September 30, 2017, the weighted average interest rate on outstanding borrowings under the First Lien
Credit Facility was 5.2%.
|
|
|
•
|
|
Contains covenants that limit our ability to incur additional indebtedness, grant liens, make loans or investments, make distributions, merge into or consolidate with other persons, enter into commodity or interest rate
swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of our assets.
|
|
|
•
|
|
Requires us to enter into commodity hedges covering at least 80% of our expected 2019 production prior to December 31, 2017.
|
We were not in compliance with certain of the financial covenants under our credit facilities as of December 31, 2016, as well as the
requirement to deliver audited financial statements without a going concern qualification. On April 19, 2017, we, Titan Energy Operating, LLC (our wholly owned subsidiary), as borrower, and certain subsidiary guarantors entered into a third
amendment to the First Lien Credit Facility with Wells Fargo, as administrative agent, and the lenders party thereto. Pursuant to the third amendment, certain of the financial ratio covenants were revised upwards. Specifically, beginning
December 31, 2017, we will be required to maintain a ratio of Total Debt to EBITDA (each as defined in the First Lien Credit Facility) of not more than 5.50 to 1.00 for each fiscal quarter through December 31, 2018 and of not more than
5.00 to 1.00 thereafter. We will also be required, beginning December 31, 2017, to maintain a ratio of First Lien Debt (as defined in the First Lien Credit Facility) to EBITDA of not more than 4.00 to 1.00 for each fiscal quarter through
December 31, 2018 and of not more than 3.50 to 1.00 thereafter.
In addition to the amendments to the financial ratio covenants, the
First Lien Credit Facility lenders waived certain defaults by us with respect to the fourth quarter of 2016, including compliance with the ratios of Total Debt to EBITDA and First Lien Debt to EBITDA, as well as our obligation to deliver financial
statements without a “going concern” qualification. The First Lien Credit Facility lenders’ waivers were subject to revocation in certain circumstances, including the exercise of remedies by junior lenders (including pursuant to our
second lien credit facility), the failure to extend the
180-day
standstill period under the intercreditor agreement at least 15 business days prior to its expiration, and the occurrence of additional events of
default under the First Lien Credit Facility.
The third amendment to the First Lien Credit Facility confirmed the conforming and
non-conforming
tranches of the borrowing base at $410 million and $30 million, respectively, but required us to take actions (which included asset sales) to reduce the conforming tranche of the borrowing
base to $330 million by August 31, 2017 and to $190 million by October 1, 2017 (subject to extension at the administrative agent’s option to October 31, 2017). Similarly, the
non-conforming
tranche of the borrowing base was required to be reduced to $10 million by November 1, 2017. In addition, we were required to use excess asset sale proceeds (after application in
accordance with the existing terms of the First Lien Credit Facility) to repay outstanding borrowings and reduce the applicable borrowing base to the required level.
On June 30, 2017, we completed a majority of the Appalachian Assets sale for net cash proceeds of $65.6 million, which included
customary preliminary purchase price adjustments, all of which was used to repay a portion of the outstanding indebtedness under our First Lien Credit Facility. On August 7, 2017, we completed the Rangely Assets sale for net cash proceeds of
$103.5 million, which included customary preliminary purchase price adjustments, all of which was used to repay a portion of the outstanding indebtedness under our First Lien Credit Facility and achieve compliance with the requirement to reduce
our First Lien Credit Facility borrowings below $360 million, as required by August 31, 2017. On September 29, 2017, we completed the remainder of the Appalachia Assets sale for additional cash proceeds of $10.4 million, all of
which was used to repay a portion of outstanding borrowings under our First Lien Credit Facility.
22
On November 6, 2017, we entered into a fourth amendment to our First Lien Credit Facility.
The fourth amendment has an effective date of October 31, 2017 and confirms the conforming and
non-conforming
tranches of the borrowing base at $228.7 million and $30 million, respectively, but
requires us to take actions (which can include asset sales and equity offerings) to reduce the conforming tranche of the borrowing base to $190 million by December 8, 2017 and to $150 million by August 31, 2018. The maturity date
of the
non-conforming
tranche of the borrowing base was confirmed as May 1, 2018. We are required to use proceeds from asset sales to make prepayments.
In addition to the requirements above, the First Lien Credit Facility lenders also agreed to a limited waiver of certain existing defaults
with respect to financial covenants, required repayments of borrowings and other related matters. The waiver terminates upon the earliest of (i) December 8, 2017, (ii) the occurrence of additional events of default under the First Lien
Credit Facility and (iii) the exercise of remedies under our Second Lien Credit Facility. Pursuant to the fourth amendment, we are required to hedge at least 50% and 80% of our 2019 projected proved developed producing production by
December 31, 2017 and March 31, 2018, respectively.
Second Lien Credit Facility
On September 1, 2016, we entered into our Second Lien Credit Facility with Wilmington Trust, National Association, as administrative
agent, and the lenders party thereto for an aggregate principal amount of $252.5 million maturing on February 23, 2020. A summary of the key provisions of the Second Lien Credit Facility is as follows (of which certain provisions have been
modified through subsequent amendments as described further below):
|
|
•
|
|
Until May 1, 2017, interest will be payable at a rate of 2% in cash plus
paid-in-kind
interest at a rate equal to the Adjusted LIBO
Rate (as defined in the Second Lien Credit Facility) plus 9% per annum. During the subsequent
15-month
period, cash and
paid-in-kind
interest will vary based on a pricing grid tied to our leverage ratio under the First Lien Credit Facility. After such
15-month
period, interest will accrue at a rate equal to the Adjusted LIBO Rate plus 9% per annum and will be payable in cash.
|
|
|
•
|
|
All prepayments are subject to the following premiums, plus accrued and unpaid interest:
|
|
|
•
|
|
4.5% of the principal amount prepaid for prepayments prior to February 23, 2017;
|
|
|
•
|
|
2.25% of the principal amount prepaid for prepayments on or after February 23, 2017 and prior to February 23, 2018; and
|
|
|
•
|
|
no premium for prepayments on or after February 23, 2018.
|
|
|
•
|
|
Obligations are secured on a second priority basis by security interests in the same collateral securing the First Lien Credit Facility and are guaranteed by certain of our material subsidiaries, and any
non-guarantor
subsidiaries of ours are minor.
|
|
|
•
|
|
Contains covenants that limit our ability to make restricted payments, take on indebtedness, issue preferred stock, grant liens, conduct sales of assets and subsidiary stock, make distributions from restricted
subsidiaries, conduct affiliate transactions, engage in other business activities, and other covenants substantially similar to those in the First Lien Credit Facility, including, among others, restrictions on swap agreements, debt of unrestricted
subsidiaries, drilling and operating agreements and the sale or discount of receivables.
|
|
|
•
|
|
Requires us to maintain certain financial ratios (the financial ratios used an annualized EBITDA measurement for periods prior to June 30, 2017):
|
|
|
•
|
|
EBITDA to Interest Expense (each as defined in the Second Lien Credit Facility) of not less than 2.50 to 1.00;
|
|
|
•
|
|
Total Leverage Ratio (as defined in the Second Lien Credit Facility) of no greater than 5.5 to 1.0 prior to December 31, 2017 and no greater than 5.0 to 1.0 thereafter; and
|
|
|
•
|
|
Current assets to current liabilities (each as defined in the Second Lien Credit Facility) of not less than 1.0 to 1.0.
|
On April 21, 2017, the lenders under the our Second Lien Credit Facility delivered a Notice, pursuant to which they noticed events of
default related to financial covenants and the failure to deliver financial statements without a “going concern” qualification. The delivery of the Notice began the
180-day
standstill period under
the intercreditor agreement, during which the lenders under the Second Lien Credit Facility were prevented from pursuing remedies against the collateral securing our obligations under the Second Lien Credit Facility. The lenders have not accelerated
the payment of amounts outstanding under the Second Lien Credit Facility.
On September 27, 2017, the lenders under our Second Lien
Credit Facility entered into the Extension Letter with us and the lenders under our First Lien Credit Facility. Pursuant to the Extension Letter, the Second Lien Credit Facility lenders agreed to extend the
180-day
standstill period under the intercreditor agreement (during which the lenders under the Second Lien Credit Facility were prevented from pursuing remedies against the collateral securing the
Company’s obligations under the Second Lien Credit Facility) by
23
an additional 35 days from October 18, 2017 to November 22, 2017. In addition, the extension of the standstill period extends the waiver of certain defaults under the First Lien Credit
Facility, which terminates 15 business days prior to the expiration of the standstill period. The parties agreed to extend the standstill period to provide the Company with additional time to negotiate proposed amendments to each of the First Lien
Credit Facility and the Second Lien Credit Facility.
In connection with, and as a condition to, the effectiveness of the fourth amendment
to our First Lien Credit Facility, on November 6, 2017, the lenders under our Second Lien Credit Facility agreed to extend the standstill period under the intercreditor agreement (during which the lenders under the Second Lien Credit Facility
are prevented from pursuing remedies against the collateral securing our obligations under the Second Lien Credit Facility) until December 29, 2017.
NOTE 6 – DERIVATIVE INSTRUMENTS
We
use a number of different derivative instruments, principally swaps and options, in connection with our commodity price risk management activities. We do not apply hedge accounting to any of our derivative instruments. As a result, gains and losses
associated with derivative instruments are recognized in earnings.
We enter into commodity future option contracts to achieve more
predictable cash flows by hedging our exposure to changes in commodity prices. At any point in time, such contracts may include regulated New York Mercantile Stock Exchange (“NYMEX”) futures and options contracts and
non-regulated
over-the-counter
futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting
positions, but may be settled by the physical delivery of the commodity. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. NGL fixed price swaps are priced based on a WTI crude oil index, while ethane, propane,
butane and iso butane contracts are priced based on the respective Mt. Belvieu price. These contracts were recorded at their fair values.
Pursuant to the Restructuring Support Agreement, our Predecessor completed the sale of substantially all of its commodity hedge positions on
July 25, 2016 and July 26, 2016 and used the proceeds to repay $233.5 million of borrowings outstanding under the Predecessor’s first lien credit facility.
The following table summarizes the commodity derivative activity and presentation in our condensed consolidated statements of operations for
the periods indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
|
Predecessor
|
|
|
|
|
Three Months
Ended
September 30,
2017
|
|
|
Nine Months
Ended
September 30,
2017
|
|
|
Period from
September 1,
2016 through
September 30,
2016
|
|
|
|
|
|
|
Period from
July 1,
2016 through
August 31,
2016
|
|
|
Period from
January 1,
2016 through
August 31,
2016
|
|
|
Portion of settlements associated with gains previously recognized within accumulated other
comprehensive income, net of prior year offsets
(1)(2)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
$
|
1,461
|
|
|
$
|
10,387
|
|
|
Portion of settlements attributable to subsequent mark to market gains (losses)
(2)
|
|
|
1,666
|
|
|
|
(2,309
|
)
|
|
|
191
|
|
|
|
|
|
|
|
3,440
|
|
|
|
80,604
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cash settlements on commodity derivative contracts
(2)
|
|
$
|
1,666
|
|
|
$
|
(2,309
|
)
|
|
$
|
191
|
|
|
|
|
|
|
$
|
4,901
|
|
|
$
|
90,991
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gains (losses) recognized on cash
settlement
(3)
|
|
$
|
195
|
|
|
$
|
20,409
|
|
|
$
|
(43
|
)
|
|
|
|
|
|
$
|
9,381
|
|
|
$
|
(9,444
|
)
|
|
Gains (losses) recognized on open derivative
contracts
(3)
|
|
|
(4,263
|
)
|
|
|
16,516
|
|
|
|
(2,036
|
)
|
|
|
|
|
|
|
(7,028
|
)
|
|
|
(13,804
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gains (losses) on
mark-to-market
derivatives
|
|
$
|
(4,068
|
)
|
|
$
|
36,925
|
|
|
$
|
(2,079
|
)
|
|
|
|
|
|
$
|
2,353
|
|
|
$
|
(23,248
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Recognized in gas and oil production revenue.
|
|
(2)
|
The Predecessor periods presented exclude the effects of the $214.9 million and the $20.4 million allocated to discontinued operations (see Note 3), net of $8.2 million in hedge monetization fees, paid
directly to the First Lien Credit Facility lenders upon the sale of substantially all of our Predecessor’s commodity hedge positions on July 25, 2016 and July 26, 2016. The $8.2 million in hedge monetization fees was not
allocated to discontinued operations as this was recorded in reorganization items, net on the condensed consolidated statements of operations.
|
|
(3)
|
Recognized in gain (loss) on
mark-to-market
derivatives.
|
24
The following table summarizes the gross fair values of our derivative instruments, presenting
the impact of offsetting the derivative assets and liabilities included on our condensed consolidated balance sheets for the periods indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
Amounts
Recognized
|
|
|
Gross
Amounts
Offset
|
|
|
Net Amount
Presented
|
|
|
Offsetting Derivatives as of September 30, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current portion of derivative assets
|
|
$
|
2,038
|
|
|
$
|
(2,006
|
)
|
|
$
|
32
|
|
|
Long-term portion of derivative assets
|
|
|
168
|
|
|
|
(168
|
)
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative assets
|
|
$
|
2,206
|
|
|
$
|
(2,174
|
)
|
|
$
|
32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current portion of derivative liabilities
|
|
$
|
(5,635
|
)
|
|
$
|
2,006
|
|
|
$
|
(3,629
|
)
|
|
Long-term portion of derivative liabilities
|
|
|
(1,064
|
)
|
|
|
168
|
|
|
|
(896
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative liabilities
|
|
$
|
(6,699
|
)
|
|
$
|
2,174
|
|
|
$
|
(4,525
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Offsetting Derivatives as of December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current portion of derivative assets
|
|
$
|
7
|
|
|
$
|
(7
|
)
|
|
$
|
—
|
|
|
Long-term portion of derivative assets
|
|
|
677
|
|
|
|
(677
|
)
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative assets
|
|
$
|
684
|
|
|
$
|
(684
|
)
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current portion of derivative liabilities
|
|
$
|
(30,526
|
)
|
|
$
|
7
|
|
|
$
|
(30,519
|
)
|
|
Long-term portion of derivative liabilities
|
|
|
(13,885
|
)
|
|
|
677
|
|
|
|
(13,208
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative liabilities
|
|
$
|
(44,411
|
)
|
|
$
|
684
|
|
|
$
|
(43,727
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At September 30, 2017, we had the following commodity derivatives instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Type
|
|
Production
Period Ending
December 31,
|
|
|
Volumes
(1)
|
|
|
Average
Fixed Price
(2)
|
|
|
Fair Value
Asset / (Liability)
|
|
|
Total Type
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
(2)
|
|
|
(in thousands)
|
|
|
Natural Gas – Fixed Price Swaps
|
|
|
201
|
7
(3)
|
|
|
12,919,900
|
|
|
$
|
3.140
|
|
|
$
|
693
|
|
|
|
|
|
|
|
|
|
2018
|
|
|
|
43,947,300
|
|
|
$
|
2.959
|
|
|
$
|
(3,458
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(2,765
|
)
|
|
Crude Oil – Fixed Price Swaps
|
|
|
2017
|
(3)
|
|
|
196,500
|
|
|
$
|
47.441
|
|
|
$
|
(766
|
)
|
|
|
|
|
|
|
|
|
2018
|
|
|
|
588,500
|
|
|
$
|
50.286
|
|
|
$
|
(936
|
)
|
|
|
|
|
|
|
|
|
2019
|
|
|
|
73,000
|
|
|
|
50.630
|
|
|
|
(26
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(1,728
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net liability
|
|
|
$
|
(4,493
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Volumes for natural gas are stated in million British Thermal Units. Volumes for crude oil are stated in barrels.
|
|
(2)
|
Fair value for natural gas fixed price swaps are based on forward NYMEX natural gas prices, as applicable. Fair value of crude oil fixed price swaps are based on forward West Texas Intermediate (“WTI”) index
crude oil prices, as applicable.
|
|
(3)
|
The production volumes for 2017 include the remaining three months of 2017 beginning October 1, 2017.
|
NOTE 7 – FAIR VALUE OF FINANCIAL INSTRUMENTS
Assets and Liabilities Measured on a Recurring Basis
We use a market approach fair value methodology to value our outstanding derivative contracts. The fair value of a financial instrument depends
on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. We separate the fair value of our financial instruments into the three level hierarchy (Levels 1, 2 and 3) based on
our assessment of the availability of observable market data and the significance of
non-observable
data used to determine fair value. As of September 30, 2017 and December 31, 2016, all of our
derivative financial instruments were classified as Level 2.
25
Information for financial instruments measured at fair value were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives, Fair Value, as of September 30, 2017
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
|
Assets, gross
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity swaps
|
|
$
|
—
|
|
|
$
|
2,206
|
|
|
$
|
—
|
|
|
$
|
2,206
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative assets, gross
|
|
|
—
|
|
|
|
2,206
|
|
|
|
—
|
|
|
|
2,206
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities, gross
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity swaps
|
|
|
—
|
|
|
|
(6,699
|
)
|
|
|
—
|
|
|
|
(6,699
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative liabilities, gross
|
|
|
—
|
|
|
|
(6,699
|
)
|
|
|
—
|
|
|
|
(6,699
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives, fair value, net
|
|
$
|
—
|
|
|
$
|
(4,493
|
)
|
|
$
|
—
|
|
|
$
|
(4,493
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives, Fair Value, as of December 31, 2016
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
|
Assets, gross
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity swaps
|
|
$
|
—
|
|
|
$
|
684
|
|
|
$
|
—
|
|
|
$
|
684
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative assets, gross
|
|
|
—
|
|
|
|
684
|
|
|
|
—
|
|
|
|
684
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities, gross
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity swaps
|
|
|
—
|
|
|
|
(44,411
|
)
|
|
|
—
|
|
|
|
(44,411
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative liabilities, gross
|
|
|
—
|
|
|
|
(44,411
|
)
|
|
|
—
|
|
|
|
(44,411
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives, fair value, net
|
|
$
|
—
|
|
|
$
|
(43,727
|
)
|
|
$
|
—
|
|
|
$
|
(43,727
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Financial Instruments
Our other current assets and liabilities on our condensed consolidated balance sheets are considered to be financial instruments. The estimated
fair values of these instruments approximate their carrying amounts due to their short-term nature and thus are categorized as Level 1. The estimated fair value of our long-term debt at September 30, 2017, which consists of our First Lien
Credit Facility and Second Lien Credit Facility, approximated carrying value of $539.8 million. At September 30, 2017, the carrying value of outstanding borrowings under our First Lien Credit Facility, which bears interest at variable
interest rates, approximated estimated fair value. The estimated fair value of our Second Lien Credit Facility was based upon the market approach and calculated using yields of our Second Lien Credit Facility as provided by financial institutions
and thus were categorized as Level 3 values.
Assets and Liabilities Measured at Fair Value on a
Non-Recurring
Basis
We estimated the fair value less estimated costs to sell of our remaining
Appalachia Assets and Rangely Assets held for sale (see Note 3) based on the respective negotiated purchase prices that were derived from discounted cash flow models, which considered the estimated remaining lives of the wells based on reserve
estimates, future operating and development costs of the assets, the respective natural gas, oil and natural gas liquids forward price curves, external estimates of recovery values, and other market multiples. These estimates of fair value are
Level 3 measurements as they are based on unobservable inputs.
Our Predecessor’s management estimated the fair values of
natural gas and oil properties transferred to our Predecessor upon consolidation of certain Drilling Partnerships (see Note 8) based on a discounted cash flow model, which considered the estimated remaining lives of the wells based on reserve
estimates, our Predecessor’s future operating and development costs of the assets, the respective natural gas, oil and natural gas liquids forward price curves and estimated salvage values using our historical experience and external estimates
of recovery values. These estimates of fair value were Level 3 measurements as they were based on unobservable inputs.
Our
Predecessor’s management estimated the fair value of asset retirement obligations transferred to our Predecessor upon consolidation of certain Drilling Partnerships (see Note 8) based on discounted cash flow projections using our
Predecessor’s historical experience in plugging and abandoning wells, the estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future considering inflation
rates, federal and state regulatory requirements, and our Predecessor’s assumed credit-adjusted risk-free interest rate. These estimates of fair value were Level 3 measurements as they were based on unobservable inputs.
We estimated the fair value of our enterprise value and reorganizational value of assets and liabilities upon our emergence from bankruptcy
through fresh-start accounting (see Note 2) utilizing the discounted cash flow method for both our gas and oil production business and our partnership management business based on the financial projections in our disclosure statement. The resulting
fair value of our equity was used to value shares issued under our incentive plan. These estimates of fair value are Level 3 measurements as they are based on unobservable inputs.
26
NOTE 8 – CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
Relationship with ATLS
. Except for our named executive officers, we do not directly employ any persons to manage or operate our
business. These functions are provided by employees of ATLS and/or its affiliates. As of September 30, 2017, we had a $1.8 million payable to ATLS for payroll and benefit costs related to ATLS employees managing and operating our business,
which was recorded as a current liability within advances from affiliates on our condensed consolidated balance sheet. As of September 30, 2017 we reclassified $15.1 million of receivables from ATLS originating prior to our Chapter 11
Filings to
non-current
due to the uncertainty of collecting this balance within the next twelve months, which was recorded within
non-current
advances to affiliates on
our condensed consolidated balance sheet. As of December 31, 2016, we had net receivables of $3.3 million from ATLS related to the timing of funding cash accounts related to general and administrative expenses, such as payroll and
benefits, and amounts originating prior to our Chapter 11 Filings, which was recorded as a net current asset within in advances to affiliates in our condensed consolidated balance sheets.
Relationship with Drilling Partnerships
. We conduct certain activities through, and a portion of our revenues are attributable to,
sponsorship of the Drilling Partnerships. We serve as general partner and operator of the Drilling Partnerships and assume customary rights and obligations for the Drilling Partnerships. As the general partner, we are liable for the Drilling
Partnerships’ liabilities and can be liable to limited partners of the Drilling Partnerships if we breach our responsibilities with respect to the operations of the Drilling Partnerships. We are entitled to receive management fees,
reimbursement for administrative costs incurred and to share in the Drilling Partnership’s revenue and costs and expenses according to the respective partnership agreements. On June 30, 2017, in connection with the completion of the sale
of the majority of the Appalachian Assets, we delegated the operational activities to an affiliate of Diversified for all the Drilling Partnerships’ natural gas and oil wells in Pennsylvania and Tennessee.
In March 2016, our Predecessor transferred $36.7 million of investor capital raised and $13.3 million of accrued well drilling and
completion costs incurred by our Predecessor to the Atlas Eagle Ford 2015 L.P. private drilling partnership for activities directly related to their program. In June 2016, our Predecessor transferred $3.8 million of funds to certain of the
Drilling Partnerships that were projected to make monthly or quarterly distributions to their limited partners over the next several months and/or quarters to ensure accessible distribution funding coverage in accordance with the respective Drilling
Partnerships’ operations and partnership agreements in the event that our Predecessor experienced a prolonged restructuring period as our Predecessor performed all administrative and management functions for the Drilling Partnerships.
During the Predecessor period from January 1, 2016 to August 31, 2016, our Predecessor recorded $7.2 million and
$12.4 million of gas and oil properties and asset retirement obligations, respectively, transferred to our Predecessor as a result of certain Drilling Partnership consolidations. The gas and oil properties and asset retirement obligations were
recorded at their fair values on the respective dates of the Drilling Partnerships’ consolidation and transfer to our Predecessor (see Note 7) and resulted in a
non-cash
loss of $6.1 million, net of
consolidation and transfer adjustments, for the Predecessor period from January 1, 2016 through August 31, 2016, which was recorded in net income (loss) from discontinued operations in the consolidated statements of operations.
During the Predecessor periods from July 1, 2016 to August 31, 2016 and from January 1, 2016 to August 31, 2016, we
recognized a $10.9 million provision for losses on Drilling Partnership receivables related to the write down of certain receivables to their estimated net realizable values, which is recorded in loss from discontinued operations on our
consolidated statement of operations. As of December 31, 2016, we had trade receivables of $0.1 million from certain of the Drilling Partnerships, which were recorded in accounts receivable in our condensed consolidated balance sheet. As
of September 30, 2017 and December 31, 2016, we had trade payables of $3.2 million and $5.6 million, respectively, to certain of the Drilling Partnerships, which were recorded in accounts payable in our condensed consolidated
balance sheets.
Relationship with AGP
. At the direction of ATLS, we charge direct costs, such as salaries and wages, and allocate
indirect costs, such as rent and other general and administrative costs, to AGP based on the number of ATLS employees who devoted time to AGP’s activities. As of September 30, 2017 and December 31, 2016, we had receivables of
$0.1 million and $0.8 million, respectively, from AGP related to AGP’s direct costs and indirect cost allocation, which was recorded in advances to affiliates in our condensed consolidated balance sheets.
Other Relationships
. We have other related party transactions with regard to certain funds advised and
sub-advised
by GSO Capital Partners LP and its affiliates (“GSO”) as GSO funds are majority lenders under our Second Lien Credit Facility and GSO funds hold an excess of
ten-percent
of our common shares.
27
NOTE 9 – COMMITMENTS AND CONTINGENCIES
Drilling Partnership Commitments
As of
September 30, 2017, we are committed to expend approximately $2.8 million, principally on a new enterprise resource planning system and drilling and completion expenditures.
Environmental Matters
We and our
subsidiaries are subject to various federal, state and local laws and regulations relating to the protection of the environment. We have established procedures for the ongoing evaluation of our and our subsidiaries’ operations, to identify
potential environmental exposures and to comply with regulatory policies and procedures. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition
caused by past operations and do not contribute to current or future revenue generation are expensed. Liabilities are recorded when environmental assessments and/or
clean-ups
are probable, and the costs can be
reasonably estimated. We and our subsidiaries maintain insurance which may cover in whole or in part certain environmental expenditures. We and our subsidiaries had no environmental matters requiring specific disclosure or requiring the recognition
of a liability as of September 30, 2017 and December 31, 2016.
Legal Proceedings
We are party to various routine legal proceedings arising out of the ordinary course of our business. We believe that none of these actions,
individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows.
NOTE 10 –
PREDECESSOR CASH DISTRIBUTIONS
Our Predecessor had a monthly cash distribution program whereby it distributed all of its available
cash (as defined in its partnership agreement) for that month to its unitholders within 45 days from the month end. If our Predecessor’s common unit distributions in any quarter exceed specified target levels, ATLS received between 13% and 48%
of such distributions in excess of the specified target levels.
During the Predecessor period from January 1, 2016 through
August 31, 2016, our Predecessor paid four monthly cash distributions totaling $5.1 million to its common limited partners ($0.0125 per unit per month); $2.5 million to its Preferred Class C limited partners ($0.0125 per unit per
month); and $0.2 million to its General Partner Class A holder ($0.0125 per unit per month).
During the Predecessor period from
January 1, 2016 through August 31, 2016, our Predecessor paid two distributions totaling $4.4 million to its Class D Preferred limited partners ($0.5390625 per unit) for the period October 15, 2015 through April 14,
2016. During the Predecessor period from January 1, 2016 through August 31, 2016, our Predecessor paid two distributions totaling $0.3 million to its Class E Preferred limited partners ($0.671875 per unit) for the period
October 15, 2015 through April 14, 2016. On June 16, 2016, our Predecessor’s Board of Directors elected to suspend its quarterly distributions on its Class D Preferred Units and our Class E Preferred Units, beginning
with the second quarter 2016 distribution, due to the continued lower commodity price environment. The Class D Preferred Units and Class E Preferred Units accrued distributions of $3.4 million and $0.3 million, respectively, from
April 15, 2016 through August 31, 2016. However, due to the distribution suspension and our Predecessor’s Chapter 11 filings, these amounts were not earned as the preferred units were cancelled without receipt of any consideration on
the Plan Effective Date.
NOTE 11 – OPERATING SEGMENT INFORMATION
Our operations include two reportable operating segments: gas and oil production and Drilling Partnership management. The Drilling Partnership
management segment includes all of our managing and operating activities specific to the Drilling Partnerships including well construction and completion, administration and oversight, well services, and gathering and processing. These operating
segments reflect the way we manage our operations and make business decisions.
We previously presented three reportable operating
segments; however, due to the decline in investor capital funds raised in recent years, anticipated lower levels of future investor capital fund raise, and the consolidation of certain historical Drilling Partnerships in 2016, we aggregated our well
construction and completion segment with our other partnership management segment to report all of our Drilling Partnership management activities in one combined segment as they do not meet the quantitative threshold for reporting individual segment
information. As a result of this change, we have restated our prior year condensed consolidated statements of operations and segment footnote disclosures to conform to our current presentation.
28
Operating segment data for the periods indicated were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
|
Predecessor
|
|
|
|
|
Three Months
Ended
September 30,
2017
|
|
|
Period
September 1
through
30, 2016
|
|
|
|
|
|
|
Period
July 1 through
August 31, 2016
|
|
|
Gas and oil production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas and oil production revenues
(1)
|
|
$
|
43,356
|
|
|
$
|
15,182
|
|
|
|
|
|
|
$
|
38,643
|
|
|
Gas and oil production costs
|
|
|
(21,633
|
)
|
|
|
(9,854
|
)
|
|
|
|
|
|
|
(18,577
|
)
|
|
Depreciation, depletion and amortization
|
|
|
(11,646
|
)
|
|
|
(4,882
|
)
|
|
|
|
|
|
|
(14,723
|
)
|
|
Loss on divestiture
|
|
|
(5,177
|
)
|
|
|
—
|
|
|
|
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment income
|
|
$
|
4,900
|
|
|
$
|
446
|
|
|
|
|
|
|
$
|
5,343
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling partnership
management:
(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling partnership management revenues
|
|
$
|
1,997
|
|
|
$
|
2,074
|
|
|
|
|
|
|
$
|
18,778
|
|
|
Drilling partnership management expenses
|
|
|
(248
|
)
|
|
|
(1,266
|
)
|
|
|
|
|
|
|
(16,121
|
)
|
|
Depreciation, depletion and amortization expense
|
|
|
(288
|
)
|
|
|
(270
|
)
|
|
|
|
|
|
|
(5,862
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment income (loss)
|
|
$
|
1,461
|
|
|
$
|
538
|
|
|
|
|
|
|
$
|
(3,205
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of segment income (loss) to net loss:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas and oil production
|
|
$
|
4,900
|
|
|
$
|
446
|
|
|
|
|
|
|
$
|
5,343
|
|
|
Drilling partnership management
(2)
|
|
|
1,461
|
|
|
|
538
|
|
|
|
|
|
|
|
(3,205
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total segment income
|
|
|
6,361
|
|
|
|
984
|
|
|
|
|
|
|
|
2,138
|
|
|
General and administrative
expenses
(3)
|
|
|
(10,142
|
)
|
|
|
(4,530
|
)
|
|
|
|
|
|
|
(5,128
|
)
|
|
Interest expense
(3)
|
|
|
(15,268
|
)
|
|
|
(3,470
|
)
|
|
|
|
|
|
|
(14,087
|
)
|
|
Gain (loss) on asset sales and
disposal
(3)
|
|
|
(82
|
)
|
|
|
5
|
|
|
|
|
|
|
|
(18
|
)
|
|
Reorganization items, net
(3)
|
|
|
—
|
|
|
|
(353
|
)
|
|
|
|
|
|
|
(16,614
|
)
|
|
Other income (loss)
(3)
|
|
|
(777
|
)
|
|
|
—
|
|
|
|
|
|
|
|
(3,063
|
)
|
|
Income tax (provision) benefit
(3)
|
|
|
202
|
|
|
|
—
|
|
|
|
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(19,706
|
)
|
|
$
|
(7,364
|
)
|
|
|
|
|
|
$
|
(36,772
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of segment revenues to total revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas and oil production
(1)
|
|
$
|
43,356
|
|
|
$
|
15,182
|
|
|
|
|
|
|
$
|
38,643
|
|
|
Drilling partnership management
|
|
|
1,997
|
|
|
|
2,074
|
|
|
|
|
|
|
|
18,778
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
45,353
|
|
|
$
|
17,256
|
|
|
|
|
|
|
$
|
57,421
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas and oil production
|
|
$
|
4,279
|
|
|
$
|
5,464
|
|
|
|
|
|
|
$
|
5,529
|
|
|
Drilling partnership management
|
|
|
—
|
|
|
|
(115
|
)
|
|
|
|
|
|
|
496
|
|
|
Corporate and other
|
|
|
325
|
|
|
|
18
|
|
|
|
|
|
|
|
49
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capital expenditures
|
|
$
|
4,604
|
|
|
$
|
5,367
|
|
|
|
|
|
|
$
|
6,074
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
|
Predecessor
|
|
|
|
|
Nine Months
Ended
September 30,
2017
|
|
|
Period
September 1
through
30, 2016
|
|
|
|
|
|
|
Period
January 1 through
August 31, 2016
|
|
|
Gas and oil production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas and oil production revenues
(1)
|
|
$
|
197,855
|
|
|
$
|
15,182
|
|
|
|
|
|
|
$
|
105,829
|
|
|
Gas and oil production costs
|
|
|
(74,355
|
)
|
|
|
(9,854
|
)
|
|
|
|
|
|
|
(80,988
|
)
|
|
Depreciation, depletion and amortization
|
|
|
(37,455
|
)
|
|
|
(4,882
|
)
|
|
|
|
|
|
|
(62,142
|
)
|
|
Loss on divestiture
|
|
|
(43,369
|
)
|
|
|
—
|
|
|
|
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment income (loss)
|
|
$
|
42,676
|
|
|
$
|
446
|
|
|
|
|
|
|
$
|
(37,301
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling partnership
management:
(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling partnership management revenues
|
|
$
|
17,387
|
|
|
$
|
2,074
|
|
|
|
|
|
|
$
|
24,446
|
|
|
Drilling partnership management expenses
|
|
|
(10,026
|
)
|
|
|
(1,266
|
)
|
|
|
|
|
|
|
(17,427
|
)
|
|
Depreciation, depletion and amortization expense
|
|
|
(947
|
)
|
|
|
(270
|
)
|
|
|
|
|
|
|
(11,130
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment income (loss)
|
|
$
|
6,414
|
|
|
$
|
538
|
|
|
|
|
|
|
$
|
(4,111
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of segment income (loss) to net loss:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas and oil production
(1)
|
|
$
|
42,676
|
|
|
$
|
446
|
|
|
|
|
|
|
$
|
(37,301
|
)
|
|
Drilling partnership management
|
|
|
6,414
|
|
|
|
538
|
|
|
|
|
|
|
|
(4,111
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total segment income (loss)
|
|
|
49,090
|
|
|
|
984
|
|
|
|
|
|
|
|
(41,412
|
)
|
|
General and administrative
expenses
(3)
|
|
|
(32,961
|
)
|
|
|
(4,530
|
)
|
|
|
|
|
|
|
(41,038
|
)
|
|
Interest expense
(3)
|
|
|
(41,816
|
)
|
|
|
(3,470
|
)
|
|
|
|
|
|
|
(71,059
|
)
|
|
Gain on early extinguishment of
debt
(3)
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
26,498
|
|
|
Gain (loss) on asset sales and disposal
(3)
|
|
|
25
|
|
|
|
5
|
|
|
|
|
|
|
|
(551
|
)
|
|
Reorganization items, net
(3)
|
|
|
—
|
|
|
|
(353
|
)
|
|
|
|
|
|
|
(16,614
|
)
|
|
Other income (loss)
(3)
|
|
|
(925
|
)
|
|
|
—
|
|
|
|
|
|
|
|
(3,063
|
)
|
|
Income tax (provision) benefit
(3)
|
|
|
11,503
|
|
|
|
—
|
|
|
|
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(15,084
|
)
|
|
$
|
(7,364
|
)
|
|
|
|
|
|
$
|
(147,239
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of segment revenues to total revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas and oil production
(1)
|
|
$
|
197,855
|
|
|
$
|
15,182
|
|
|
|
|
|
|
$
|
105,829
|
|
|
Drilling partnership management
|
|
|
17,387
|
|
|
|
2,074
|
|
|
|
|
|
|
|
24,446
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
215,242
|
|
|
$
|
17,256
|
|
|
|
|
|
|
$
|
130,275
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas and oil production
|
|
$
|
36,191
|
|
|
$
|
5,464
|
|
|
|
|
|
|
$
|
22,684
|
|
|
Drilling partnership management
|
|
|
521
|
|
|
|
(115
|
)
|
|
|
|
|
|
|
2,046
|
|
|
Corporate and other
|
|
|
527
|
|
|
|
18
|
|
|
|
|
|
|
|
164
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capital expenditures
|
|
$
|
37,239
|
|
|
$
|
5,367
|
|
|
|
|
|
|
$
|
24,894
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Includes gain (loss) on
mark-to-market
derivatives. The Predecessor period from January 1, 2016 through August 31, 2016 includes
a $23.2 million loss on
mark-to-market
derivatives related to increases in commodity future prices relative to our commodity fixed price swaps.
|
|
(2)
|
Includes revenues and expenses from our Drilling Partnership management activities, including well construction and completion, well services, gathering and processing, administration and oversight that do not meet the
quantitative threshold for reporting individual segment information.
|
|
(3)
|
General and administrative expenses, interest expense, gain on early extinguishment of debt, gain (loss) on asset sales and disposal, reorganization items, net,, other income (loss) and income tax (provision) benefit
have not been allocated to reportable segments as it would be impracticable to reasonably do so for the periods presented.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30,
2017
|
|
|
December 31,
2016
|
|
|
Balance sheet:
|
|
|
|
|
|
|
|
|
|
Total assets:
|
|
|
|
|
|
|
|
|
|
Gas and oil production
|
|
$
|
556,607
|
|
|
$
|
703,243
|
|
|
Drilling partnership management
|
|
|
5,476
|
|
|
|
11,786
|
|
|
Corporate and other
(1)
|
|
|
43,342
|
|
|
|
44,129
|
|
|
Assets held for sale
|
|
|
—
|
|
|
|
122,676
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
605,425
|
|
|
$
|
881,834
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Corporate and other primarily consists of cash and cash equivalents, advances to affiliates and other assets, net, which have not been allocated to reportable segments.
|
30
|
ITEM 2:
|
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
BUSINESS OVERVIEW
We are a publicly
traded (OTCQX: TTEN) Delaware limited liability company and an independent developer and producer of natural gas, crude oil and NGLs with operations in basins across the United States but primarily focused on the horizontal development of resource
potential from the Eagle Ford Shale in South Texas. As discussed further below, we are the successor to the business and operations of Atlas Resource Partners, L.P. (“ARP”). Unless the context otherwise requires, references to “Titan
Energy, LLC,” “Titan,” “the Company,” “we,” “us,” and “our,” refer to Titan Energy, LLC and our consolidated subsidiaries (and our predecessor, where applicable).
Titan Energy Management, LLC (“Titan Management”) manages us and holds our Series A Preferred Share, which entitles Titan Management
to receive 2% of the aggregate of distributions paid to shareholders (as if it held 2% of our members’ equity, subject to dilution as discussed below) and to appoint four of our seven directors. Titan Management is a wholly owned subsidiary of
Atlas Energy Group, LLC (“ATLS”; OTCQX: ATLS), which is a publicly traded company.
In addition to its preferred member interest
in us, ATLS also holds general and limited partner interests in Atlas Growth Partners, L.P. (“AGP”), a Delaware limited partnership and an independent developer and producer of natural gas, oil and NGLs, with operations primarily focused
in the Eagle Ford Shale, and in Lightfoot Capital Partners, L.P. and Lightfoot Capital Partners GP, LLC, which incubate new MLPs and invest in existing MLPs.
ARP Restructuring and Emergence from Chapter 11 Proceedings
On July 25, 2016, ARP and certain of its subsidiaries and ATLS, solely with respect to certain sections thereof, entered into a
Restructuring Support Agreement (the “Restructuring Support Agreement”) with certain of their lenders (the “Restructuring Support Parties”) to support ARP’s restructuring pursuant to a
pre-packaged
plan of reorganization (the “Plan”).
On July 27, 2016, ARP and
certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 in the United States Bankruptcy Court for the Southern District of New York (the “Bankruptcy Court,” and the cases commenced thereby, the “Chapter 11
Filings”). The cases commenced thereby were jointly administered under the caption “In re: ATLAS RESOURCE PARTNERS, L.P., et al.”
On August 26, 2016, an order confirming the Plan was entered by the Bankruptcy Court. On September 1, 2016, (the “Plan
Effective Date”), pursuant to the Plan, the following occurred:
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•
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ARP’s first lien lenders received cash payment of all obligations owed to them by ARP pursuant to the senior secured revolving credit facility (other than $440 million of principal and face amount of letters
of credit) and became lenders under our first lien exit facility credit agreement, composed of a $410 million conforming reserve-based tranche and a $30 million
non-conforming
tranche (the
“First Lien Credit Facility”).
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•
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ARP’s second lien lenders received a pro rata share of our second lien exit facility credit agreement with an aggregate principal amount of $252.5 million (the “Second Lien Credit Facility”). In
addition, ARP’s second lien lenders received a pro rata share of 10% of our common shares, subject to dilution by a management incentive plan.
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•
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ARP’s senior note holders, in exchange for 100% of the $668 million aggregate principal amount of senior notes outstanding plus accrued but unpaid interest as of the commencement of the Chapter 11 Filings,
received 90% of our common shares, subject to dilution by a management incentive plan.
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•
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all of ARP’s preferred limited partnership units and common limited partnership units were cancelled without the receipt of any consideration or recovery.
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•
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ARP transferred all of its assets and operations to us as a new holding company and ARP dissolved. As a result, we became the successor issuer to ARP for purposes of and pursuant to Rule
12g-3
of the Securities Exchange Act of 1934, as amended.
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•
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Titan Management, a wholly owned subsidiary of ATLS, received a Series A Preferred Share, which entitles Titan
Management to receive 2% of the aggregate of distributions paid to shareholders (as if it held 2% of our members’ equity, subject to dilution if
catch-up
contributions are not made with respect to future
equity issuances, other than pursuant to the management incentive plan) and certain other rights as provided for in the Restructuring Support Agreement. Four of the seven initial members of the board of directors were designated by Titan Management
(the “Titan Class A Directors”). For so long as Titan Management holds such preferred share, the Titan Class A Directors will be appointed by a majority of the Titan Class A Directors then in office. We have a continuing
right to purchase the preferred share at fair market
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31
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value (as determined pursuant to the methodology provided for in our limited liability company agreement), subject to the receipt of certain approvals, including the holders of at least 67% of
the outstanding common shares of us unaffiliated with Titan Management voting in favor of the exercise of the right to purchase the preferred share.
|
LIQUIDITY AND ABILITY TO CONTINUE AS A GOING CONCERN
Since the Plan Effective Date, we have funded our operations through cash flows generated from our operations and cash on hand. We currently do
not have the capacity to access additional liquidity from our First Lien Credit Facility and our ability to access public equity and debt markets may be limited. Our future cash flows are subject to a number of variables, including oil and natural
gas prices. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and continue to remain low in 2017. These lower commodity prices have negatively impacted our revenues, earnings and cash flows, which has
negatively impacted our ability to remain in compliance with the covenants under our credit facilities. Sustained low commodity prices could have a material and adverse effect on our liquidity position.
Even following the amendments described below, we continue to face liquidity issues and are currently considering, and are likely to make,
changes to our capital structure to maintain sufficient liquidity, meet our debt obligations and manage and strengthen our balance sheet. If we are not able to enter into further amendments with our lenders prior to the expiration of the standstill
period, we may be forced to seek further options as described below.
We were not in compliance with certain of the financial covenants
under our credit facilities as of December 31, 2016, as well as the requirement to deliver audited financial statements without a going concern qualification. As a result of the amendment referenced below, our financial covenants will not be
tested again until the quarter ending December 31, 2017. We do not currently have sufficient liquidity to repay all of our outstanding indebtedness, and as a result, there is substantial doubt regarding our ability to continue as a going
concern. We have classified $538.1 million of outstanding indebtedness under our credit facilities, which is net of $1.7 million of deferred financing costs, as current portion of long term debt, net within our condensed consolidated
balance sheet as of September 30, 2017, based on the occurrence of the event of default, the lenders under our credit facilities, as applicable, could elect to declare all amounts outstanding immediately due and payable and the lenders could
terminate all commitments to extend further credit.
On April 19, 2017, we entered into an amendment to our First Lien Credit
Facility (which has been superseded by subsequent amendments as described further below). This amendment provided for, among other things, waivers of our
non-compliance,
increases in certain financial covenant
ratios and scheduled decreases in our borrowing base (
refer to Note 5 of our condensed consolidated financial statements for further information regarding the specific amended terms and provisions
). As part of our overall business strategy,
we have continued to execute on our sales of
non-core
assets, which has included the sale of our Appalachia and Rangely operations (
see “Recent Developments”
). The proceeds of the consummated
asset sales were used to repay borrowings under our First Lien Credit Facility. Our strategy is to continue to sell
non-core
assets to reduce our leverage position, which will also help us to comply with the
requirements of our First Lien Credit Facility amendments.
In addition to the amendments to the financial ratio covenants, the First Lien
Credit Facility lenders waived certain defaults by us with respect to the fourth quarter of 2016, including compliance with the ratios of Total Debt to EBITDA and First Lien Debt to EBITDA, as well as our obligation to deliver financial statements
without a “going concern” qualification. The First Lien Credit Facility lenders’ waivers were subject to revocation in certain circumstances, including the exercise of remedies by junior lenders (including pursuant to our Second Lien
Credit Facility), the failure to extend the standstill period under the intercreditor agreement at least 15 business days prior to its expiration, and the occurrence of additional events of default under the First Lien Credit Facility.
On April 21, 2017, the lenders under the our Second Lien Credit Facility delivered a notice of events of default and reservation of
rights, pursuant to which they noticed events of default related to financial covenants and the failure to deliver financial statements without a “going concern” qualification. The delivery of such notice began the
180-day
standstill period under the intercreditor agreement, during which the lenders under the Second Lien Credit Facility were prevented from pursuing remedies against the collateral securing our obligations under
the Second Lien Credit Facility. The lenders have not accelerated the payment of amounts outstanding under the Second Lien Credit Facility.
On September 27, 2017, the lenders under our Second Lien Credit Facility entered into a letter agreement with us and the lenders under
our First Lien Credit Facility (the “Extension Letter”) (which has been superseded by subsequent amendments as described further below). Pursuant to the Extension Letter, the Second Lien Credit Facility lenders agreed to extend the
180-day
standstill period under the intercreditor agreement (during which the lenders under the Second Lien Credit Facility were prevented from pursuing remedies against the collateral securing the Company’s
obligations under the Second Lien Credit Facility) by an additional 35 days from October 18, 2017 to November 22, 2017. In addition, the extension of the standstill period extended the waiver of certain defaults under the First Lien Credit
Facility, which terminates 15 business days prior to the expiration of the standstill period. The parties agreed to extend the standstill period to provide the Company with additional time to negotiate proposed amendments to each of the First Lien
Credit Facility and the Second Lien Credit Facility.
32
On September 29, 2017, we completed the remainder of the Appalachia Assets sale for
additional cash proceeds of $10.4 million, all of which was used to repay a portion of outstanding borrowings under our First Lien Credit Facility.
On November 6, 2017, we entered into a fourth amendment to our First Lien Credit Facility. The fourth amendment has an effective date of
October 31, 2017 and confirms the conforming and
non-conforming
tranches of the borrowing base at $228.7 million and $30 million, respectively, but requires us to take actions (which can include
asset sales and equity offerings) to reduce the conforming tranche of the borrowing base to $190 million by December 8, 2017 and to $150 million by August 31, 2018. The maturity date of the
non-conforming
tranche of the borrowing base was confirmed as May 1, 2018. We are required to use proceeds from asset sales to make prepayments.
In addition to the requirements above, the First Lien Credit Facility lenders also agreed to a limited waiver of certain existing defaults
with respect to financial covenants, required repayments of borrowings and other related matters. The waiver terminates upon the earliest of (i) December 8, 2017, (ii) the occurrence of additional events of default under the First Lien
Credit Facility and (iii) the exercise of remedies under our Second Lien Credit Facility. Pursuant to the fourth amendment, we are required to hedge at least 50% and 80% of our 2019 projected proved developed producing production by
December 31, 2017 and March 31, 2018, respectively.
In connection with, and as a condition to, the effectiveness of the fourth
amendment to our First Lien Credit Facility, the lenders under our Second Lien Credit Facility agreed to extend the standstill period under the intercreditor agreement (during which the lenders under the Second Lien Credit Facility are prevented
from pursuing remedies against the collateral securing our obligations under the Second Lien Credit Facility) until December 29, 2017.
We continually review and may make changes to our capital structure from time to time, with the goal of strengthening our balance sheet and
meeting our debt service obligations. We could pursue options such as refinancing, restructuring or reorganizing our indebtedness or capital structure or seek to raise additional capital through debt or equity financing to address our liquidity
concerns and high debt levels. We are evaluating various options, but there is no certainty that we will be able to implement any such options, and we cannot provide any assurances that any refinancing or changes in our debt or equity capital
structure would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all, and such options may result in a wide range of outcomes for our stakeholders.
We cannot assure you that we will be able to implement the above actions, if necessary, on commercially reasonable terms, or at all, in a
manner that will be permitted under the terms of our debt instruments or in a manner that does not negatively impact the price of our securities. Additionally, there can be no assurance that the above actions will allow us to meet our debt
obligations and capital requirements.
RECENT DEVELOPMENTS
Appalachia Divestiture
On May 4,
2017, we entered into a definitive agreement to sell our conventional Appalachia and Marcellus assets to Diversified Gas & Oil, PLC (“Diversified”) for $84.2 million. The transaction includes the sale of approximately 8,400
oil and gas wells across Pennsylvania, Ohio, Tennessee, New York and West Virginia, along with the associated infrastructure (the “Appalachian Assets”). We retained our Utica Shale position, Indiana assets and West Virginia CBM assets in
the region. On June 30, 2017, we completed a majority of the Appalachian Assets sale for net cash proceeds of $65.6 million, which included customary preliminary purchase price adjustments, all of which was used to repay a portion of the
outstanding indebtedness under our First Lien Credit Facility.
On September 29, 2017, we completed the remainder of the Appalachia
Assets sale for additional cash proceeds of $10.4 million, all of which was used to repay a portion of outstanding borrowings under our First Lien Credit Facility.
Rangely Divestiture
On June 12,
2017, we entered into a definitive agreement to sell our 25% interest in Rangely Field to an affiliate of Merit Energy Company, LLC for $105 million. Rangely is a CO
2
flood located in Rio
Blanco County, Colorado, and operated by Chevron. The transaction includes the sale of our interest in Rangely Field, its 22% interest in Raven Ridge Pipeline, a CO
2
transportation line, as
well as surrounding acreage in Rio Blanco and Moffat Counties, Colorado (collectively, the “Rangely Assets”). On August 7, 2017, we completed the Rangely Assets sale for net cash proceeds of $103.5 million, which included
customary preliminary purchase price adjustments, all of which was used to repay a portion of the outstanding indebtedness under our First Lien Credit Facility and achieve compliance with the requirement to reduce our First Lien Credit Facility
borrowings below $360 million, as required by August 31, 2017.
33
GENERAL TRENDS AND OUTLOOK
We expect our business to be affected by key trends in natural gas and oil production markets. Our expectations are based on assumptions made
by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.
The natural gas, oil and natural gas liquids commodity price markets have suffered significant declines since the fourth quarter of 2014 and
continue to remain low in 2017. The causes of these declines are based on a number of factors, including, but not limited to, a significant increase in natural gas, oil and NGL production. While we anticipate continued high levels of exploration and
production activities over the long-term in the areas in which we operate, fluctuations in energy prices can greatly affect production rates and investments in the development of new natural gas, oil and NGL reserves.
Our future gas and oil reserves, production, cash flow, and our ability to make payments on our debts, depend on our success in producing our
current reserves efficiently, developing our existing acreage and acquiring additional proved reserves economically. We face the challenge of natural production declines and volatile natural gas, oil and NGL prices. As initial reservoir pressures
are depleted, natural gas and oil production from particular wells decrease. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce. To the extent we do not have sufficient
capital, our ability to drill and acquire more reserves will be negatively impacted. Based on current market conditions, we believe that a reduction in our debt and cash interest obligations is needed to improve our financial position and
flexibility and to position us to take advantage of opportunities that may arise out of the current industry downturn.
RESULTS OF OPERATIONS
We sponsored and continue to manage
tax-advantaged
investment partnerships (the “Drilling
Partnerships”), in which we coinvested, to finance a portion of our natural gas, crude oil and NGL production activities.
Matters Impacting
Comparability of Results
Fresh Start Accounting
. Upon our emergence from bankruptcy, we adopted fresh-start
accounting in accordance with ASC 852. We qualified for fresh-start accounting because (i) the reorganization value of our assets immediately prior to the confirmation was less than the post-petition liabilities and allowed claims and
(ii) the holders of existing voting shares of our predecessor company received less than 50% of the voting shares of the post-emergence successor entity.
As a result of the application of fresh start accounting, at the Plan Effective Date, our assets and liabilities were recorded at their
estimated fair values which, in some cases, are significantly different than amounts included in our financial statements prior to the Plan Effective Date. Accordingly, our financial condition, results of operations, and cash flows on and after the
Plan Effective Date are not comparable to our financial condition, results of operations, and cash flows prior to the Plan Effective Date. References to “Successor” relate to Titan on and subsequent to the Plan Effective Date. References
to “Predecessor” refer to ARP prior to the Plan Effective Date. We have presented our financial condition, results of operations, and cash flows with a black line division to delineate the lack of comparability between the amounts
presented on or after September 1, 2016 and dates prior.
Reclassifications
.
Certain reclassifications have been
made to our condensed consolidated financial statements for the prior year periods to conform to classifications used in the current year, specifically related to our Appalachian Assets presented as discontinued operations in the condensed
consolidated financial statements and footnote disclosures and our segment information on the condensed consolidated statement of operations and segment footnote disclosures.
Discontinued operations.
We determined the Appalachian Assets represent discontinued operations as they constitute a disposal of
a group of components and a strategic shift that will have a major effect on our operations and financial results. We evaluated the Appalachian Assets sale on our gas and oil production and Drilling Partnership management segments’ results of
operations and cash flows, as well as expected asset retirement obligations, and concluded the impact will have a major effect on our expected operations and financial results. As a result, we reclassified the Appalachian Assets from their
historical presentation to assets and liabilities held for sale on the condensed consolidated balance sheet and to net income (loss) from discontinued operations on the condensed consolidated statement of operations for all periods presented.
Segments
. Our operations include two reportable operating segments: gas and oil production and Drilling Partnership management.
The Drilling Partnership management segment includes all of our managing and operating activities specific to the Drilling Partnerships including well construction and completion, administration and oversight, well services, and gathering and
processing. These operating segments reflect the way we manage our operations and make business decisions.
We previously presented three
reportable operating segments; however, due to the decline in investor capital funds raised in recent years, anticipated lower levels of future investor capital fund raise, and the consolidation of certain historical Drilling
34
Partnerships in 2016, we aggregated our well construction and completion segment with our other partnership management segment to report all of our Drilling Partnership management activities in
one combined segment as they do not meet the quantitative threshold for reporting individual segment information. As a result of this change, we have restated our prior year condensed consolidated statements of operations and segment footnote
disclosures to conform to our current presentation.
GAS AND OIL PRODUCTION
Production Profile
. Currently, we have natural gas, crude oil and NGL production operations in various plays throughout the
United States. We have established production positions in the following operating areas:
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the Eagle Ford Shale in south Texas, in which we acquired acreage and producing wells in November 2014;
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•
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Coalbed Methane producing natural gas assets in (1) the Raton Basin in northern New Mexico and southern Colorado, acquired in 2013; (2) the Black Warrior Basin in central Alabama, acquired in 2013; (3) the Central
Appalachia Basin in West Virginia and Virginia, acquired in 2014; and (4) the Arkoma Basin in eastern Oklahoma, acquired in 2015;
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•
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the Appalachia Basin assets, including the Utica Shale, and the New Albany Shale in southwestern Indiana; and
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•
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the
Mid-Continent
assets, including Barnett Shale and Marble Falls plays, both in the Fort Worth Basin in northern Texas and acquired in 2012, and the Mississippi Lime and Hunton
plays in northwestern Oklahoma.
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We also had a production position in the Rangely field in northwest Colorado, a mature
tertiary CO2 flood with
low-decline
oil production, where we had a 25%
non-operated
net working interest position which we acquired in 2014 and subsequently sold in
August 2017.
The following table presents the number of wells we drilled and the number of wells we turned in line, both gross and for
our interest, during the periods indicated:
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Successor
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Predecessor
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Three Months
Ended
September 30,
2017
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Period
September 1
through
September 30,
2016
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Period July 1
through
August 31,
2016
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Gross wells drilled
(3)
:
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Eagle Ford
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—
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|
—
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|
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2
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Net wells drilled
(1)
:
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|
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Eagle Ford
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—
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|
—
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|
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2
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|
Gross wells turned in
line
(2)(3)
:
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Eagle Ford
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|
—
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|
4
|
|
|
|
|
|
|
|
—
|
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|
Net wells turned in
line
(1)(2)(3)
:
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Eagle Ford
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—
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|
1
|
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—
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Successor
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Predecessor
|
|
|
|
|
Nine Months
Ended
September 30,
2017
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|
|
Period
September 1
through
September 30,
2016
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|
|
|
|
|
Period
January 1
through
August 31,
2016
|
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|
Gross wells drilled
(3)
:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford
|
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|
4
|
|
|
|
—
|
|
|
|
|
|
|
|
2
|
|
|
Net wells drilled
(1)
:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford
|
|
|
3
|
|
|
|
—
|
|
|
|
|
|
|
|
2
|
|
|
Gross wells turned in
line
(2)(3)
:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford
|
|
|
4
|
|
|
|
4
|
|
|
|
|
|
|
|
—
|
|
|
Net wells turned in
line
(1)(2)(3)
:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford
|
|
|
3
|
|
|
|
1
|
|
|
|
|
|
|
|
—
|
|
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(1)
|
Includes (i) our percentage interest in the wells in which we have had a direct ownership interest and (ii) our percentage interest in the wells based on our percentage ownership in the Drilling Partnerships.
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(2)
|
Wells turned in line refers to wells that have been drilled, completed, and connected to a gathering system.
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35
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(3)
|
There were no exploratory wells drilled during the periods presented. There were no gross or net dry wells within any of our operating areas during the periods presented.
|
Production Volumes
. The following table presents our total net natural gas, crude oil, and NGL production volumes per day in
each of our operating areas and total production for each of the periods indicated:
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|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
|
Predecessor
|
|
|
|
|
Three Months
Ended
September 30,
2017
|
|
|
Period
September 1,
through
September 30,
2016
|
|
|
|
|
|
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Period
July 1,
through
August 31,
2016
|
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Production volumes per
day:
(1)(2)
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Mcfd)
|
|
|
613
|
|
|
|
423
|
|
|
|
|
|
|
|
457
|
|
|
Oil (Bpd)
|
|
|
2,218
|
|
|
|
1,025
|
|
|
|
|
|
|
|
1,028
|
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|
NGLs (Bpd)
|
|
|
136
|
|
|
|
88
|
|
|
|
|
|
|
|
95
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Total (Mcfed)
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|
|
14,736
|
|
|
|
7,102
|
|
|
|
|
|
|
|
7,197
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
Coal-bed
Methane:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Mcfd)
|
|
|
103,673
|
|
|
|
114,030
|
|
|
|
|
|
|
|
114,100
|
|
|
Oil (Bpd)
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
—
|
|
|
NGLs (Bpd)
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (Mcfed)
|
|
|
103,673
|
|
|
|
114,030
|
|
|
|
|
|
|
|
114,100
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
Utica / Indiana:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Mcfd)
|
|
|
3,914
|
|
|
|
4,841
|
|
|
|
|
|
|
|
5,136
|
|
|
Oil (Bpd)
|
|
|
20
|
|
|
|
43
|
|
|
|
|
|
|
|
43
|
|
|
NGLs (Bpd)
|
|
|
15
|
|
|
|
23
|
|
|
|
|
|
|
|
25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (Mcfed)
|
|
|
4,121
|
|
|
|
5,240
|
|
|
|
|
|
|
|
5,540
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mid-Continent:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Mcfd)
|
|
|
30,674
|
|
|
|
34,508
|
|
|
|
|
|
|
|
34,499
|
|
|
Oil (Bpd)
|
|
|
193
|
|
|
|
299
|
|
|
|
|
|
|
|
325
|
|
|
NGLs (Bpd)
|
|
|
1,190
|
|
|
|
1,447
|
|
|
|
|
|
|
|
1,440
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (Mcfed)
|
|
|
38,970
|
|
|
|
44,985
|
|
|
|
|
|
|
|
45,091
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rangely:
(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Mcfd)
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
—
|
|
|
Oil (Bpd)
|
|
|
817
|
|
|
|
2,229
|
|
|
|
|
|
|
|
2,214
|
|
|
NGLs (Bpd)
|
|
|
34
|
|
|
|
232
|
|
|
|
|
|
|
|
242
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (Mcfed)
|
|
|
5,103
|
|
|
|
14,766
|
|
|
|
|
|
|
|
14,736
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production volumes per day:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Mcfd)
|
|
|
138,873
|
|
|
|
153,802
|
|
|
|
|
|
|
|
154,192
|
|
|
Oil (Bpd)
|
|
|
3,247
|
|
|
|
3,597
|
|
|
|
|
|
|
|
3,611
|
|
|
NGLs (Bpd)
|
|
|
1,374
|
|
|
|
1,790
|
|
|
|
|
|
|
|
1,801
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (Mcfed)
|
|
|
166,602
|
|
|
|
186,122
|
|
|
|
|
|
|
|
186,664
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production:
(1)(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
12,776
|
|
|
|
4,614
|
|
|
|
|
|
|
|
9,560
|
|
|
Oil (MBbls)
|
|
|
299
|
|
|
|
108
|
|
|
|
|
|
|
|
224
|
|
|
NGLs (MBbls)
|
|
|
126
|
|
|
|
54
|
|
|
|
|
|
|
|
112
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MMcfe)
|
|
|
15,327
|
|
|
|
5,584
|
|
|
|
|
|
|
|
11,573
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
|
|
Predecessor
|
|
|
|
|
Nine Months
Ended
September 30,
2017
|
|
|
Period
September 1,
through
September 30,
2016
|
|
|
|
|
|
|
|
Period
January 1,
through
August 31,
2016
|
|
|
Production volumes per
day:
(1)(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Mcfd)
|
|
|
621
|
|
|
|
423
|
|
|
|
|
|
|
|
|
|
437
|
|
|
Oil (Bpd)
|
|
|
2,072
|
|
|
|
1,025
|
|
|
|
|
|
|
|
|
|
1,212
|
|
|
NGLs (Bpd)
|
|
|
137
|
|
|
|
88
|
|
|
|
|
|
|
|
|
|
91
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (Mcfed)
|
|
|
13,874
|
|
|
|
7,102
|
|
|
|
|
|
|
|
|
|
8,257
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal-bed
Methane:
(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Mcfd)
|
|
|
105,835
|
|
|
|
114,030
|
|
|
|
|
|
|
|
|
|
117,491
|
|
|
Oil (Bpd)
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
—
|
|
|
NGLs (Bpd)
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (Mcfed)
|
|
|
105,835
|
|
|
|
114,030
|
|
|
|
|
|
|
|
|
|
117,491
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utica / Indiana:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Mcfd)
|
|
|
4,163
|
|
|
|
4,841
|
|
|
|
|
|
|
|
|
|
5,748
|
|
|
Oil (Bpd)
|
|
|
26
|
|
|
|
43
|
|
|
|
|
|
|
|
|
|
47
|
|
|
NGLs (Bpd)
|
|
|
17
|
|
|
|
23
|
|
|
|
|
|
|
|
|
|
25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (Mcfed)
|
|
|
4,417
|
|
|
|
5,240
|
|
|
|
|
|
|
|
|
|
6,182
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mid-Continent:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Mcfd)
|
|
|
31,229
|
|
|
|
34,508
|
|
|
|
|
|
|
|
|
|
38,111
|
|
|
Oil (Bpd)
|
|
|
225
|
|
|
|
299
|
|
|
|
|
|
|
|
|
|
432
|
|
|
NGLs (Bpd)
|
|
|
1,224
|
|
|
|
1,447
|
|
|
|
|
|
|
|
|
|
1,654
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (Mcfed)
|
|
|
39,927
|
|
|
|
44,985
|
|
|
|
|
|
|
|
|
|
50,627
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rangely
(3)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Mcfd)
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
—
|
|
|
Oil (Bpd)
|
|
|
1,648
|
|
|
|
2,229
|
|
|
|
|
|
|
|
|
|
2,287
|
|
|
NGLs (Bpd)
|
|
|
153
|
|
|
|
232
|
|
|
|
|
|
|
|
|
|
244
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (Mcfed)
|
|
|
10,802
|
|
|
|
14,766
|
|
|
|
|
|
|
|
|
|
15,187
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production volumes per day:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Mcfd)
|
|
|
141,848
|
|
|
|
153,802
|
|
|
|
|
|
|
|
|
|
161,786
|
|
|
Oil (Bpd)
|
|
|
3,971
|
|
|
|
3,597
|
|
|
|
|
|
|
|
|
|
3,979
|
|
|
NGLs (Bpd)
|
|
|
1,530
|
|
|
|
1,790
|
|
|
|
|
|
|
|
|
|
2,014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (Mcfed)
|
|
|
174,855
|
|
|
|
186,122
|
|
|
|
|
|
|
|
|
|
197,745
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production:
(1)(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
38,725
|
|
|
|
4,614
|
|
|
|
|
|
|
|
|
|
39,476
|
|
|
Oil (MBbls)
|
|
|
1,084
|
|
|
|
108
|
|
|
|
|
|
|
|
|
|
971
|
|
|
NGLs (MBbls)
|
|
|
418
|
|
|
|
54
|
|
|
|
|
|
|
|
|
|
491
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MMcfe)
|
|
|
47,735
|
|
|
|
5,584
|
|
|
|
|
|
|
|
|
|
48,250
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Production quantities consist of the sum of (i) our proportionate share of production from wells in which we have a direct interest, based on our proportionate net revenue interest in such wells, and (ii) our
proportionate share of production from wells owned by the Drilling Partnerships in which we have an interest, based on our equity interest in each such Drilling Partnership and based on each Drilling Partnership’s proportionate net revenue
interest in these wells.
|
|
(2)
|
“MMcf” represents million cubic feet; “MMcfe” represent million cubic feet equivalents; “Mcfd” represents thousand cubic feet per day; “Mcfed” represents thousand cubic feet
equivalents per day; and “Bbls” and “Bpd” represent barrels and barrels per day. Barrels are converted to Mcfe using the ratio of approximately 6 Mcf to one barrel.
|
|
(3)
|
We sold our interest in Rangely on August 7, 2017 (see “Recent Developments”).
|
37
Production Revenues, Prices and Costs
. Our production revenues and estimated gas
and oil reserves are substantially dependent on prevailing market prices for natural gas and oil. The following table presents our production revenues and average sales prices for our natural gas, oil, and natural gas liquids production, along with
our average production costs, which include lease operating expenses, taxes, and transportation costs, for each of the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
|
Predecessor
|
|
|
|
|
Three
Months
Ended
September 30,
2017
|
|
|
Period
September 1
through
September 30,
2016
|
|
|
|
|
|
|
Period July 1
through
August 31,
2016
|
|
|
Production revenues (in
thousands):
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas revenue
|
|
$
|
155
|
|
|
$
|
35
|
|
|
|
|
|
|
$
|
92
|
|
|
Oil revenue
|
|
|
9,699
|
|
|
|
1,306
|
|
|
|
|
|
|
|
1,960
|
|
|
Natural gas liquids revenue
|
|
|
253
|
|
|
|
45
|
|
|
|
|
|
|
|
86
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
10,107
|
|
|
$
|
1,386
|
|
|
|
|
|
|
$
|
2,138
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal-bed
Methane:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas revenue
|
|
$
|
26,256
|
|
|
$
|
9,628
|
|
|
|
|
|
|
$
|
22,077
|
|
|
Oil revenue
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
—
|
|
|
Natural gas liquids revenue
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
26,256
|
|
|
$
|
9,628
|
|
|
|
|
|
|
$
|
22,077
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utica / Indiana:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas revenue
|
|
$
|
920
|
|
|
$
|
339
|
|
|
|
|
|
|
$
|
736
|
|
|
Oil revenue
|
|
|
66
|
|
|
|
50
|
|
|
|
|
|
|
|
91
|
|
|
Natural gas liquids revenue
|
|
|
19
|
|
|
|
7
|
|
|
|
|
|
|
|
15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
1,005
|
|
|
$
|
396
|
|
|
|
|
|
|
$
|
842
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mid-Continent:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas revenue
|
|
$
|
5,816
|
|
|
$
|
2,165
|
|
|
|
|
|
|
$
|
5,252
|
|
|
Oil revenue
|
|
|
814
|
|
|
|
362
|
|
|
|
|
|
|
|
624
|
|
|
Natural gas liquids revenue
|
|
|
2,007
|
|
|
|
609
|
|
|
|
|
|
|
|
1,070
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
8,637
|
|
|
$
|
3,136
|
|
|
|
|
|
|
$
|
6,946
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rangely:
(7)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas revenue
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
$
|
—
|
|
|
Oil revenue
|
|
|
2,599
|
|
|
|
2,843
|
|
|
|
|
|
|
|
4,393
|
|
|
Natural gas liquids revenue
|
|
|
118
|
|
|
|
214
|
|
|
|
|
|
|
|
452
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
2,717
|
|
|
$
|
3,057
|
|
|
|
|
|
|
$
|
4,845
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas revenue
|
|
$
|
33,147
|
|
|
$
|
12,167
|
|
|
|
|
|
|
$
|
28,157
|
|
|
Oil revenue
|
|
|
13,178
|
|
|
|
4,561
|
|
|
|
|
|
|
|
7,068
|
|
|
Natural gas liquids revenue
|
|
|
2,397
|
|
|
|
875
|
|
|
|
|
|
|
|
1,623
|
|
|
Subordinated revenue
(2)
|
|
|
(1,298
|
)
|
|
|
(342
|
)
|
|
|
|
|
|
|
(558
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
47,424
|
|
|
$
|
17,261
|
|
|
|
|
|
|
$
|
36,290
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales price:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf):
(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total realized price, after hedge
(4)
(1)
|
|
$
|
2.74
|
|
|
$
|
2.70
|
|
|
|
|
|
|
$
|
3.06
|
|
|
Total realized price, before
hedge
(4)
|
|
$
|
2.60
|
|
|
$
|
2.61
|
|
|
|
|
|
|
$
|
2.53
|
|
|
Oil (per Bbl):
(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total realized price, after hedge
(1)
|
|
$
|
43.55
|
|
|
$
|
39.92
|
|
|
|
|
|
|
$
|
41.09
|
|
|
Total realized price, before hedge
|
|
$
|
44.05
|
|
|
$
|
42.21
|
|
|
|
|
|
|
$
|
41.68
|
|
|
Natural gas liquids (per Bbl):
(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total realized price, after hedge
(1)
|
|
$
|
18.96
|
|
|
$
|
16.30
|
|
|
|
|
|
|
$
|
14.53
|
|
|
Total realized price, before hedge
|
|
$
|
18.96
|
|
|
$
|
16.30
|
|
|
|
|
|
|
$
|
14.53
|
|
38
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
|
Predecessor
|
|
|
|
|
Three
Months
Ended
September 30,
2017
|
|
|
Period
September 1
through
September 30,
2016
|
|
|
|
|
|
|
Period July 1
through
August 31,
2016
|
|
|
Production costs (per
Mcfe):
(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
1.22
|
|
|
$
|
2.03
|
|
|
|
|
|
|
$
|
1.58
|
|
|
Production taxes
|
|
|
0.39
|
|
|
|
0.49
|
|
|
|
|
|
|
|
0.48
|
|
|
Transportation and compression
|
|
|
0.05
|
|
|
|
0.14
|
|
|
|
|
|
|
|
0.16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1.66
|
|
|
$
|
2.66
|
|
|
|
|
|
|
$
|
2.23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal-bed
Methane:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
1.08
|
|
|
$
|
1.06
|
|
|
|
|
|
|
$
|
0.97
|
|
|
Production taxes
|
|
|
0.20
|
|
|
|
0.24
|
|
|
|
|
|
|
|
0.21
|
|
|
Transportation and compression
|
|
|
0.10
|
|
|
|
0.19
|
|
|
|
|
|
|
|
0.18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1.37
|
|
|
$
|
1.48
|
|
|
|
|
|
|
$
|
1.37
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utica / Indiana:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
0.54
|
|
|
$
|
0.46
|
|
|
|
|
|
|
$
|
0.34
|
|
|
Production taxes
|
|
|
0.12
|
|
|
|
0.06
|
|
|
|
|
|
|
|
0.06
|
|
|
Transportation and compression
|
|
|
0.08
|
|
|
|
0.12
|
|
|
|
|
|
|
|
0.11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
0.74
|
|
|
$
|
0.65
|
|
|
|
|
|
|
$
|
0.51
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mid-Continent:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
0.90
|
|
|
$
|
0.99
|
|
|
|
|
|
|
$
|
0.85
|
|
|
Production taxes
|
|
|
0.15
|
|
|
|
0.20
|
|
|
|
|
|
|
|
0.19
|
|
|
Transportation and compression
|
|
|
0.18
|
|
|
|
0.23
|
|
|
|
|
|
|
|
0.25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1.23
|
|
|
$
|
1.42
|
|
|
|
|
|
|
$
|
1.29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rangely:
(7)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
4.53
|
|
|
$
|
4.59
|
|
|
|
|
|
|
$
|
4.22
|
|
|
Production taxes
|
|
|
0.12
|
|
|
|
0.62
|
|
|
|
|
|
|
|
0.60
|
|
|
Transportation and compression
|
|
|
0.02
|
|
|
|
0.01
|
|
|
|
|
|
|
|
0.01
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
4.67
|
|
|
$
|
5.22
|
|
|
|
|
|
|
$
|
4.82
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
(5)
|
|
$
|
1.14
|
|
|
$
|
1.34
|
|
|
|
|
|
|
$
|
1.20
|
|
|
Production taxes
|
|
|
0.20
|
|
|
|
0.27
|
|
|
|
|
|
|
|
0.24
|
|
|
Transportation and compression
|
|
|
0.11
|
|
|
|
0.18
|
|
|
|
|
|
|
|
0.18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1.45
|
|
|
$
|
1.79
|
|
|
|
|
|
|
$
|
1.63
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
|
Predecessor
|
|
|
|
|
Nine
Months
Ended
September 30,
2017
|
|
|
Period
September 1
through
September 30,
2016
|
|
|
|
|
|
|
Period
January 1
through
August 31,
2016
|
|
|
Production revenues (in
thousands):
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas revenue
|
|
$
|
504
|
|
|
$
|
35
|
|
|
|
|
|
|
$
|
298
|
|
|
Oil revenue
|
|
|
27,253
|
|
|
|
1,306
|
|
|
|
|
|
|
|
14,622
|
|
|
Natural gas liquids revenue
|
|
|
701
|
|
|
|
45
|
|
|
|
|
|
|
|
305
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
28,458
|
|
|
$
|
1,386
|
|
|
|
|
|
|
$
|
15,225
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal-bed
Methane:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas revenue
|
|
$
|
83,342
|
|
|
$
|
9,628
|
|
|
|
|
|
|
$
|
69,358
|
|
|
Oil revenue
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
—
|
|
|
Natural gas liquids revenue
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
83,342
|
|
|
$
|
9,628
|
|
|
|
|
|
|
$
|
69,358
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utica / Indiana:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas revenue
|
|
$
|
3,213
|
|
|
$
|
339
|
|
|
|
|
|
|
$
|
2,520
|
|
|
Oil revenue
|
|
|
301
|
|
|
|
50
|
|
|
|
|
|
|
|
392
|
|
|
Natural gas liquids revenue
|
|
|
94
|
|
|
|
7
|
|
|
|
|
|
|
|
56
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
3,608
|
|
|
$
|
396
|
|
|
|
|
|
|
$
|
2,968
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mid-Continent
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas revenue
|
|
$
|
18,182
|
|
|
$
|
2,165
|
|
|
|
|
|
|
$
|
11,188
|
|
|
Oil revenue
|
|
|
2,820
|
|
|
|
362
|
|
|
|
|
|
|
|
1,839
|
|
|
Natural gas liquids revenue
|
|
|
5,788
|
|
|
|
609
|
|
|
|
|
|
|
|
4,010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
26,790
|
|
|
$
|
3,136
|
|
|
|
|
|
|
$
|
17,037
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rangely:
(7)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas revenue
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
$
|
—
|
|
|
Oil revenue
|
|
|
20,501
|
|
|
|
2,843
|
|
|
|
|
|
|
|
23,883
|
|
|
Natural gas liquids revenue
|
|
|
1,516
|
|
|
|
214
|
|
|
|
|
|
|
|
1,557
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
22,017
|
|
|
$
|
3,057
|
|
|
|
|
|
|
$
|
25,440
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas revenue
|
|
$
|
105,241
|
|
|
$
|
12,167
|
|
|
|
|
|
|
$
|
83,364
|
|
|
Oil revenue
|
|
|
50,875
|
|
|
|
4,561
|
|
|
|
|
|
|
|
40,736
|
|
|
Natural gas liquids revenue
|
|
|
8,099
|
|
|
|
875
|
|
|
|
|
|
|
|
5,928
|
|
|
Subordinated revenue
(2)
|
|
|
(3,285
|
)
|
|
|
(342
|
)
|
|
|
|
|
|
|
(951
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
160,930
|
|
|
$
|
17,261
|
|
|
|
|
|
|
$
|
129,077
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales price:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf):
(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total realized price, after hedge
(4)
(1)
|
|
$
|
2.70
|
|
|
$
|
2.70
|
|
|
|
|
|
|
$
|
3.39
|
|
|
Total realized price, before
hedge
(4)
|
|
$
|
2.71
|
|
|
$
|
2.61
|
|
|
|
|
|
|
$
|
1.96
|
|
|
Oil (per Bbl):
(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total realized price, after hedge
(1)
|
|
$
|
44.90
|
|
|
$
|
39.92
|
|
|
|
|
|
|
$
|
72.44
|
|
|
Total realized price, before hedge
|
|
$
|
46.76
|
|
|
$
|
42.21
|
|
|
|
|
|
|
$
|
36.94
|
|
|
Natural gas liquids (per Bbl):
(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total realized price, after hedge
(1)
|
|
$
|
19.32
|
|
|
$
|
16.30
|
|
|
|
|
|
|
$
|
13.55
|
|
|
Total realized price, before hedge
|
|
$
|
19.32
|
|
|
$
|
16.30
|
|
|
|
|
|
|
$
|
13.55
|
|
|
Production costs (per Mcfe):
(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
1.17
|
|
|
$
|
2.03
|
|
|
|
|
|
|
$
|
1.71
|
|
|
Production taxes
|
|
|
0.44
|
|
|
|
0.49
|
|
|
|
|
|
|
|
0.43
|
|
|
Transportation and compression
|
|
|
0.07
|
|
|
|
0.14
|
|
|
|
|
|
|
|
0.13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1.68
|
|
|
$
|
2.66
|
|
|
|
|
|
|
$
|
2.27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
|
Predecessor
|
|
|
|
|
Nine
Months
Ended
September 30,
2017
|
|
|
Period
September 1
through
September 30,
2016
|
|
|
|
|
|
|
Period
January 1
through
August 31,
2016
|
|
|
Coal-bed
Methane:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
1.03
|
|
|
$
|
1.06
|
|
|
|
|
|
|
$
|
1.00
|
|
|
Production taxes
|
|
|
0.23
|
|
|
|
0.24
|
|
|
|
|
|
|
|
0.17
|
|
|
Transportation and compression
|
|
|
0.12
|
|
|
|
0.19
|
|
|
|
|
|
|
|
0.25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1.39
|
|
|
$
|
1.48
|
|
|
|
|
|
|
$
|
1.43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utica / Indiana:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
0.47
|
|
|
$
|
0.46
|
|
|
|
|
|
|
$
|
0.38
|
|
|
Production taxes
|
|
|
0.11
|
|
|
|
0.06
|
|
|
|
|
|
|
|
0.06
|
|
|
Transportation and compression
|
|
|
0.11
|
|
|
|
0.12
|
|
|
|
|
|
|
|
0.11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
0.69
|
|
|
$
|
0.65
|
|
|
|
|
|
|
$
|
0.55
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mid-Continent:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
0.93
|
|
|
$
|
0.99
|
|
|
|
|
|
|
$
|
0.96
|
|
|
Production taxes
|
|
|
0.15
|
|
|
|
0.20
|
|
|
|
|
|
|
|
0.17
|
|
|
Transportation and compression
|
|
|
0.13
|
|
|
|
0.23
|
|
|
|
|
|
|
|
0.25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1.21
|
|
|
$
|
1.42
|
|
|
|
|
|
|
$
|
1.38
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rangely
: (7)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
4.76
|
|
|
$
|
4.59
|
|
|
|
|
|
|
$
|
4.33
|
|
|
Production taxes
|
|
|
0.48
|
|
|
|
0.62
|
|
|
|
|
|
|
|
0.59
|
|
|
Transportation and compression
|
|
|
0.01
|
|
|
|
0.01
|
|
|
|
|
|
|
|
0.01
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
5.24
|
|
|
$
|
5.22
|
|
|
|
|
|
|
$
|
4.92
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
(5)
|
|
$
|
1.23
|
|
|
$
|
1.34
|
|
|
|
|
|
|
$
|
1.27
|
|
|
Production taxes
|
|
|
0.24
|
|
|
|
0.27
|
|
|
|
|
|
|
|
0.12
|
|
|
Transportation and compression
|
|
|
0.11
|
|
|
|
0.18
|
|
|
|
|
|
|
|
0.22
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1.58
|
|
|
$
|
1.79
|
|
|
|
|
|
|
$
|
1.61
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
For the Predecessor periods from July 1, 2016 through August 31, 2016 and January 1, 2016 through August 31, 2016, production revenue includes the portion of settlements associated with gains and
losses on commodity derivative contracts previously recognized within accumulated other comprehensive income following our Predecessor’s decision to
de-designate
hedges beginning on January 1, 2015,
consisting of $1.5 million for natural gas for the Predecessor period from July 1, 2016 through August 31, 2016, and $2.3 million for natural gas and $8.1 million for oil for the Predecessor period from January 1, 2016
through August 31, 2016.
|
|
(2)
|
Represents the amount of subordination of our production revenue to investor partners within certain of our Drilling Partnerships. In addition to recognizing subordinated revenues, we also subordinate a corresponding
proportionate share of subordinated lease operating expenses to investor partners within certain of our Drilling Partnerships, which lowers our overall production costs. The corresponding subordinated lease operating expenses for the Successor three
and nine months ended September 30, 2017 and period from September 1 through September 30, 2016 were $0.7 million, $1.6 million and $0.1 million, respectively, and for the Predecessor periods from July 1, 2016
through August 31, 2016 and from January 1, 2016 through August 31, 2016 were $0.3 million and $0.6 million, respectively.
|
|
(3)
|
“Mcf” represents thousand cubic feet; “Mcfe” represents thousand cubic feet equivalents; and “Bbl” represents barrels.
|
|
(4)
|
For the Successor three months and nine months ended September 30, 2017, and period from September 1, 2016 through September 30, 2016, calculation includes the impact of cash settlements on commodity
derivative contracts, consisting of $1.8 million in receipts for natural gas derivative contracts and $0.1 million in payments for crude oil derivative contracts for the Successor three months ended September 30, 2017,
$0.5 million in payments for natural gas derivative contracts and $1.8 million in payments for crude oil derivative contracts for the Successor nine months ended September 30, 2017, and $0.4 million in receipts for natural gas
derivative contracts and $0.2 million in payments for crude oil derivative contracts for the Successor period from September 1, 2016 through September 30, 2016. For the Predecessor periods from July 1, 2016 through
August 31, 2016 and from January 1, 2016 through August 31, 2016, calculation includes the impact of cash settlements on commodity derivative contracts not previously included within accumulated other comprehensive income following
our Predecessor’s decision to
de-designate
hedges beginning on January 1, 2015, consisting of $3.6 million and $54.2 million in receipts associated with natural gas derivative contracts and
$0.1 million in payments and $26.4 million in receipts associated with crude oil derivative contracts.
|
|
(5)
|
Calculation excludes the impact of subordination of our production revenue to investor partners within our Drilling Partnerships for each of the periods presented. Including the effect of this subordination, the average
realized gas sales price was $2.64 per Mcf ($2.49 per Mcf before the effects of financial hedging), $2.78 per Mcf ($2.62 per Mcf before the effects of financial hedging), $2.63 per Mcf ($2.53 per Mcf before the effects of financial hedging), $3.00
per Mcf ($2.47 per Mcf before the effects of financial hedging) and $3.37 per Mcf ($1.94 per Mcf before the effects of financial hedging) for the Successor three months ended September 30, 2017, the nine months ended September 30, 2017 and
the period from September 1, 2016 through September 30, 2016 and for the Predecessor periods from July 1, 2016 through August 31, 2016 and from January 1, 2016 through August 31, 2016, respectively.
|
|
(6)
|
Excludes the effects of our proportionate share of lease operating expenses associated with subordination of our production revenue to investor partners within our Drilling Partnerships for each of the periods
presented. Including the effects of these costs, total lease operating expenses per Mcfe were $1.10 per Mcfe ($1.41 per Mcfe for total production costs), $1.20 per Mcfe ($1.55 per Mcfe for total production costs), $1.32 per Mcfe ($1.76 per Mcfe for
total production costs), $1.18 per Mcfe ($1.61 per Mcfe for total production costs) and $1.25 per Mcfe ($1.60 per Mcfe for total production costs) for the Successor periods three months ended September 30, 2017, nine months ended
September 30, 2017, and the period from September 1, 2016 through September 30, 2016 and the Predecessor periods from July 1, 2016 through January 31, 2016 and from January 1, 2016 through August 31, 2016,
respectively.
|
|
(7)
|
We sold our interest in Rangely on August 7, 2017 (see “Recent Developments”).
|
41
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
|
Predecessor
|
|
|
|
|
Three Months
Ended
September 30,
2017
|
|
|
Period
September 1
through
September 30,
2016
|
|
|
|
|
|
|
Period
July 1
through
August 31,
2016
|
|
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas and oil production revenues
|
|
$
|
47,424
|
|
|
$
|
17,261
|
|
|
|
|
|
|
$
|
36,290
|
|
|
Gas and oil production costs
|
|
$
|
(21,633
|
)
|
|
$
|
(9,854
|
)
|
|
|
|
|
|
$
|
(18,577
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
|
Predecessor
|
|
|
|
|
Nine Months
Ended
September 30,
2017
|
|
|
Period
September 1
through
September 30,
2016
|
|
|
|
|
|
|
Period
January 1
through
August 31,
2016
|
|
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas and oil production revenues
|
|
$
|
160,930
|
|
|
$
|
17,261
|
|
|
|
|
|
|
$
|
129,077
|
|
|
Gas and oil production costs
|
|
$
|
(74,355
|
)
|
|
$
|
(9,854
|
)
|
|
|
|
|
|
$
|
(80,988
|
)
|
Our gas and oil production revenues were lower during in the current quarter than the Successor period from
September 1, 2016 through September 30, 2016 and the Predecessor period from July 1, 2016 through August 31, 2016 due to decreases in production volumes at our operating areas due to natural declines and cost control operating
decisions and the sale of our interests in Rangely, partially offset by an increase in volumes at our Eagle Ford operating area due to 15 wells turned inline since the end of the third quarter 2016 and higher average realized sales prices before
hedging activities resulting from the improved commodity pricing environment.
Our gas and oil production revenues were higher in the nine
months ended September 30, 2017 than the Successor period from September 1, 2016 through September 30, 2016 and the Predecessor period from January 1, 2016 through August 31, 2016 due to higher average realized sales prices
before hedging activities resulting from the improved commodity pricing environment and an increase in volumes at our Eagle Ford operating area due to 15 wells turned inline since the end of the third quarter 2016, partially offset by decreases in
production volumes at our operating areas due to natural declines and cost control operating decisions and the sale of our interests in Rangely.
Our total production costs were lower in the current quarter than the Successor period from September 1, 2016 through September 30,
2016 and the Predecessor period from July 1, 2016 through August 31, 2016 primarily due to a decrease in lease operating expenses related to lower labor costs from employee reductions and other production cost control measures in each of
our operating areas, a decrease in transportation costs due to contract negotiations for lower rates, a decrease in property taxes, and the sale of our interests in Rangely.
Our total production costs were lower in the nine months ended September 30, 2017 than the Successor period from September 1, 2016
through September 30, 2016 and the Predecessor period from January 1, 2016 through August 31, 2016 primarily due to a decrease in lease operating expenses related to lower labor costs from employee reductions and other production cost
control measures in each of our operating areas, a decrease in transportation costs due to contract negotiations for lower rates, and the sale of our interests in Rangely; partially offset by an increase in production taxes due to higher realized
sales prices.
DRILLING PARTNERSHIP MANAGEMENT
We sponsored and continue to manage
tax-advantaged
investment partnerships (the “Drilling
Partnerships”), in which we coinvested, to finance a portion of our natural gas, crude oil and NGL production activities and generated revenues as the manager and operator of the Drilling Partnerships. Drilling Partnership investor capital
raised by us is deployed to drill and complete wells included within the partnership. As we deploy Drilling Partnership investor capital, we recognize certain management fees we are entitled to receive, including well construction and completion
revenues and a portion of administration and oversight revenues. At each period end, if we have Drilling Partnership investor capital that has not yet been deployed, we recognize a current liability titled “Liabilities Associated with Drilling
Contracts” on our condensed consolidated balance sheet. After the Drilling Partnership well is completed and turned in line, we are entitled to receive additional well services and operating fee revenues, administration and oversight fee
revenues, and gathering and processing fee revenues on a monthly basis while the well is operating and as the services are performed.
42
In addition, we are also entitled to our
pro-rata
share of Drilling
Partnership gas and oil production revenue, which generally approximates
10-30%,
which is recognized in our gas and oil production segment.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
|
Predecessor
|
|
|
|
|
Three Months
Ended
September 30,
2017
|
|
|
Period
September 1
through
September 30,
2016
|
|
|
|
|
|
|
Period
July 1
through
August 31,
2016
|
|
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling partnership management revenues
|
|
$
|
1,997
|
|
|
$
|
2,074
|
|
|
|
|
|
|
$
|
18,778
|
|
|
Drilling partnership management expenses
|
|
|
248
|
|
|
|
1,266
|
|
|
|
|
|
|
|
16,121
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
|
Predecessor
|
|
|
|
|
Nine Months
Ended
September 30,
2017
|
|
|
Period
September 1
Through
September 30,
2016
|
|
|
|
|
|
|
Period
January 1
through
August 31,
2016
|
|
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling partnership management revenues
|
|
$
|
17,387
|
|
|
$
|
2,074
|
|
|
|
|
|
|
$
|
24,446
|
|
|
Drilling partnership management expenses
|
|
|
10,026
|
|
|
|
1,266
|
|
|
|
|
|
|
|
17,427
|
|
Drilling partnership management revenues.
Our Drilling partnership management revenues were lower in
the current quarter and in the nine months ended September 30, 2017 compared to each of our Successor period from September 1, 2016 and the Predecessor periods from July 1, 2016 through August 31, 2016 and from January 1,
2016 through August 31, 2016 primarily due to a decrease in well construction and completion revenues related to the timing of drilling and completion activities for the partnership wells, which are recognized on a cost plus basis.
Drilling partnership management expenses.
Our drilling partnership management expenses were lower in the current quarter and in the
nine months ended September 30, 2017 compared to each of our Successor period from September 1, 2016 and the Predecessor periods from July 1, 2016 through August 31, 2016 and from January 1, 2016 through August 31, 2016
due to a decrease in well construction and completion expenses related to the timing of drilling and completion activities for the partnership wells, which are recognized on a percentage of completion basis.
43
OTHER REVENUES AND EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
|
Predecessor
|
|
|
|
|
Three Months
Ended
September 30,
2017
|
|
|
Period from
September 1,
2016 through
September 30,
2016
|
|
|
|
|
|
|
Period from
July 1, 2016
through
August 31,
2016
|
|
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) on
mark-to-market
derivatives
|
|
$
|
(4,068
|
)
|
|
$
|
(2,079
|
)
|
|
|
|
|
|
$
|
2,353
|
|
|
|
|
|
|
|
|
|
Other Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative
|
|
$
|
10,142
|
|
|
$
|
4,530
|
|
|
|
|
|
|
$
|
5,128
|
|
|
Depreciation, depletion and amortization
|
|
|
11,934
|
|
|
|
5,152
|
|
|
|
|
|
|
|
20,585
|
|
|
Loss on divestiture
|
|
|
(5,177
|
)
|
|
|
—
|
|
|
|
|
|
|
|
—
|
|
|
Interest expense
|
|
|
15,268
|
|
|
|
3,470
|
|
|
|
|
|
|
|
14,087
|
|
|
Gain (loss) on asset sales and disposal
|
|
|
(82
|
)
|
|
|
5
|
|
|
|
|
|
|
|
(18
|
)
|
|
Reorganization items, net
|
|
|
—
|
|
|
|
353
|
|
|
|
|
|
|
|
16,614
|
|
|
Other income (loss)
|
|
|
(777
|
)
|
|
|
—
|
|
|
|
|
|
|
|
(3,063
|
)
|
|
Income tax benefit
|
|
|
(202
|
)
|
|
|
—
|
|
|
|
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
|
Predecessor
|
|
|
|
|
Nine Months
Ended
September 30,
2017
|
|
|
Period from
September 1,
2016 through
September 30,
2016
|
|
|
|
|
|
|
Period from
January 1,
2016
through
August 31,
2016
|
|
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) on
mark-to-market
derivatives
|
|
$
|
36,925
|
|
|
$
|
(2,079
|
)
|
|
|
|
|
|
$
|
(23,248
|
)
|
|
|
|
|
|
|
|
|
Other Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative
|
|
$
|
32,961
|
|
|
$
|
4,530
|
|
|
|
|
|
|
$
|
41,038
|
|
|
Depreciation, depletion and amortization
|
|
|
38,402
|
|
|
|
5,152
|
|
|
|
|
|
|
|
73,272
|
|
|
Loss on divestiture
|
|
|
(43,369
|
)
|
|
|
—
|
|
|
|
|
|
|
|
—
|
|
|
Interest expense
|
|
|
41,816
|
|
|
|
3,470
|
|
|
|
|
|
|
|
71,059
|
|
|
Gain (loss) on asset sales and disposal
|
|
|
25
|
|
|
|
5
|
|
|
|
|
|
|
|
(551
|
)
|
|
Gain on extinguishment of debt
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
26,498
|
|
|
Reorganization items, net
|
|
|
—
|
|
|
|
353
|
|
|
|
|
|
|
|
16,614
|
|
|
Other income (loss)
|
|
|
(925
|
)
|
|
|
—
|
|
|
|
|
|
|
|
(3,063
|
)
|
|
Income tax benefit
|
|
|
(11,503
|
)
|
|
|
—
|
|
|
|
|
|
|
|
—
|
|
Gain (Loss) on
Mark-to-Market
Derivatives
. We recognize changes in the fair value of our derivatives immediately within gain (loss) on
mark-to-market
derivatives on our condensed consolidated statements of operations. The gains on
mark-to-market
derivatives
during the Successor nine months ended September 30, 2017 and the Predecessor period from July 1, 2016 through August 31, 2016 were due to decreases in commodity future prices relative to our derivative positions as of the respective
prior period end. The losses on
mark-to-market
derivatives during the Successor three months ended September 30, 2017, the Successor period from September 1,
2016 through September 30, 2016 and the Predecessor period from January 1, 2016 through August 31, 2016 were due to increases in commodity future prices relative to our Successor’s and our Predecessor’s derivative positions
as of the respective prior period end.
General and Administrative.
General and administrative expenses during the three months
ended September 30, 2017 as compared to the Predecessor period from July 1, 2016 through August 31, 2016 and the Successor period from September 1, 2016 through September 30, 2016 reflect increases in
non-recurring
transaction costs and salaries, wages and benefits, partially offset by decreases in stock compensation, syndication expense, and other corporate activities.
44
General and administrative expenses during the nine months ended September 30, 2017 as
compared to the Predecessor period from January 1, 2016 through August 31, 2016 and the Successor period from September 1, 2016 through September 30, 2016 reflect decreases in
non-recurring
transaction costs, salaries, wages and benefits, syndication expense, and other corporate activities.
Depreciation, Depletion and
Amortization
. Our depreciation, depletion and amortization expenses decreased in the current quarter as compared to the Successor period from September 1, 2016 through December 31, 2016 and the Predecessor period from July 1, 2016
through August 31, 2016 due to the application of fresh-start accounting to our proved properties on September 1, 2016, which reduced the depletable cost basis of our proved gas and oil properties resulting in lower depletion expense,
lower production volumes, and the sale of our interests in Rangely.
Our depreciation, depletion and amortization expenses were lower in
the nine months ended September 30, 2017 as compared to the Successor period from September 1, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through August 31, 2016 due to the application of
fresh-start accounting to our proved properties on September 1, 2016, which reduced the depletable cost basis of our proved gas and oil properties resulting in lower depletion expense, lower production volumes, and the sale of our interests in
Rangely.
Loss on Divestiture.
We determined that the carrying value of the Rangely Assets exceeded the fair value less costs to
sell, which resulted in an impairment of $38.2 million recognized in loss on divesture on our condensed consolidated statement of operations during the nine months ended September 30, 2017. We recognized a $5.2 million loss on asset
sale from the closing of the Rangely Assets sales during the Successor three and nine months ended September 30, 2017 resulting from final negotiations and settlement of working capital adjustments in connection with the preliminary purchase
price adjustments.
Interest Expense.
Interest expense during the Successor three months ended September 30, 2017 primarily
consisted of $10.1 million related to our Second Lien Credit Facility, $4.0 million related to our First Lien Credit Facility, and $1.4 million related to amortization of deferred financing costs, partially offset by $0.2 million
in capitalized interest. Interest expense during the Successor period from September 1, 2016 through September 30, 2016 consisted of $2.5 million related to our Second Lien Credit Facility, $1.5 million related to our First Lien
Credit Facility and $0.1 million related to amortization of deferred financing costs, partially offset by $0.6 million in capitalized interest. Interest expense during the Predecessor period from July 1, 2016 through August 31,
2016 consisted of $4.8 million related to our Predecessor’s second lien term loan, $4.1 million related to our Predecessor’s senior notes, $3.6 million related to our Predecessor’s first lien credit facility and
$3.3 million related to amortization of deferred financing costs and debt discounts, partially offset by $1.7 million in capitalized interest.
Interest expense during the Successor nine months ended September 30, 2017 primarily consisted of $26.6 million related to our
Second Lien Credit Facility, $13.1 million related to our First Lien Credit Facility, and $2.5 million related to amortization of deferred financing costs, partially offset by $0.4 million in capitalized interest. Interest expense
during the Successor period from September 1, 2016 through September 30, 2016 consisted of $2.5 million related to our Second Lien Credit Facility, $1.5 million related to our First Lien Credit Facility and $0.1 million
related to amortization of deferred financing costs, partially offset by $0.6 million in capitalized interest. Interest expense during the Predecessor period from January 1, 2016 through August 31, 2016 consisted of $32.6 million
related to our Predecessor’s senior notes, $17.4 million related to our Predecessor’s second lien term loan, $14.5 million related to amortization of deferred financing costs and debt discounts and $13.1 million related to
our Predecessor’s first lien credit facility, partially offset by $6.5 million in capitalized interest.
Gain on Early
Extinguishment of Debt
. The gain on early extinguishment of debt for the Predecessor period from January 1, 2016 through August 31, 2016 represents a $26.5 million gain related to the repurchase of a portion of our
Predecessor’s senior notes. Of the $26.5 million gain, $27.4 million related to the gain from the redemption of the principal values and accrued interest, partially offset by $0.9 million related to the accelerated amortization
of the related deferred financing costs.
Reorganization Items, Net.
Incremental costs incurred as a result of the Chapter 11
Filings, net gain on settlement of liabilities subject to compromise and reorganization adjustments, and net impact of fresh start adjustments are classified as “Reorganization items, net” in the Predecessor’s condensed consolidated
statement of operations. The following table summarizes the reorganization items:
|
|
|
|
|
|
|
Professional fees and other
|
|
$
|
(33,065
|
)
|
|
Accelerated amortization of deferred financing costs
|
|
|
(9,565
|
)
|
|
Net gain on reorganization adjustments
|
|
|
361,479
|
|
|
Net loss on fresh start adjustments
|
|
|
(335,463
|
)
|
|
|
|
|
|
|
|
Total reorganization items, net
|
|
$
|
(16,614
|
)
|
|
|
|
|
|
|
Other income (loss).
The $0.8 million loss for the Successor three months ended
September 30, 2017, includes a $1.3 million adjustment to net realizable value related to a settled escrow account receivable, partially offset by $0.6 million in transition service
45
agreement fees related to the Appalachian Assets sale. The $0.9 million loss for the Successor nine months ended September 30, 2017, represents a $1.3 million adjustment to net
realizable value related to a settled escrow account and the $0.6 million
write-off
of promotional items, partially offset by $0.6 million in transition service agreement fees related to the
Appalachian Assets sale and $0.4 million sales tax refund for equipment purchased for our Texas operations. The $3.0 million loss for the Predecessor periods from July 1, 2016 through August 31, 2016 and from January 1, 2016
through August 31, 2016 represent
non-cash
losses for the
write-off
of notes receivables with certain investors of our Drilling Partnerships.
Income Tax Provision (Benefit)
. For the Successor nine months ended September 30, 2017, we recorded a full valuation allowance
against our net deferred tax asset balance, which reduced our effective tax rate to 0.74%. We continue to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits and other deferred tax assets
will be utilized prior to their expiration. Our effective tax rate fluctuates as a result of the impact of state income taxes and permanent differences between our accounting for certain revenue or expense items and their corresponding treatment for
income tax purposes. Our effective tax rate for the nine months ended September 30, 2017 was 0.74%, which represents our expected Texas Franchise Tax liability. Our income tax provision differs from the provision computed by applying the U.S.
Federal statutory corporate income tax rate of 35% primarily due to the valuation allowance on our deferred tax assets.
LIQUIDITY AND CAPITAL
RESOURCES
See “Liquidity and Ability to Continue as a Going Concern” for additional disclosures.
Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
|
|
|
Predecessor
|
|
|
|
|
Nine Months Ended
September 30,
2017
|
|
|
Period from
September 1, 2016
through
September 30,
2016
|
|
|
|
|
|
|
Period from
January 1, 2016
through
August 31, 2016
|
|
|
Net cash provided by operating activities
|
|
$
|
28,875
|
|
|
$
|
9,398
|
|
|
|
|
|
|
$
|
221,106
|
|
|
Net cash provided by (used in) investing activities
|
|
|
148,787
|
|
|
|
(5,367
|
)
|
|
|
|
|
|
|
(24,894
|
)
|
|
Net cash used in financing activities
|
|
|
(180,527
|
)
|
|
|
(150
|
)
|
|
|
|
|
|
|
(182,137
|
)
|
Cash Flows From Operating Activities:
Successor Period from January 1, 2017 through September 30, 2017
|
|
•
|
|
consists of $46.5 million of net cash provided by continuing operating activities and $5.9 million of net cash provided by discontinued operating activities for cash receipts and disbursements attributable to
our normal monthly operating cycle for gas and oil production and Drilling Partnership management revenues, and collections net of payments for royalties, lease operating expenses, gathering, processing and transportation expenses, severance taxes,
Drilling Partnership management expenses, and general and administrative expenses; partially offset by
|
|
|
•
|
|
$21.2 million of cash paid for interest primarily due to our First Lien Credit Facility; and
|
|
|
•
|
|
cash settlement payments of $2.3 million on commodity derivative contracts.
|
Successor
Period from September 1, 2016 through September 30, 2016
|
|
•
|
|
consists of $5.8 million net cash provided by continuing operating activities and $4.3 million of net cash provided by discontinued operating activities for cash receipts and disbursements attributable to our
normal monthly operating cycle for gas and oil production and Drilling Partnership management revenues, and collections net of payments for royalties, lease operating expenses, gathering, processing and transportation expenses, severance taxes,
Drilling Partnership management expenses, and general and administrative expenses; and
|
|
|
•
|
|
cash settlement receipts of $0.2 million on commodity derivative contracts; partially offset by
|
|
|
•
|
|
reorganization costs of $0.9 million representing incremental costs incurred as a result of our Predecessor’s Chapter 11 Filings.
|
Predecessor Period from January 1, 2016 through August 31, 2016
46
|
|
•
|
|
consists of $214.4 million received from the sale of substantially all of our Predecessor’s commodity hedge positions on July 25, 2016 and July 26, 2016 pursuant to our Predecessor’s
Restructuring Support Agreement;
|
|
|
•
|
|
cash settlement receipts of $91.0 million on commodity derivative contracts; partially offset by
|
|
|
•
|
|
$20.6 million of net cash used in continuing operating activities and $15.6 million of net cash provided by discontinued operating activities for cash receipts and disbursements attributable to our
Predecessor’s normal monthly operating cycle for gas and oil production and partnership management revenues, and collections net of payments for royalties, well construction and completion activities, Drilling Partnership administrative and
oversight and well services activities, lease operating expenses, gathering, processing and transportation expenses, severance taxes, general and administrative expenses, and interest payments;
|
|
|
•
|
|
reorganization costs of $37.4 million incurred as a result of our Predecessor’s Chapter 11 Filings;
|
|
|
•
|
|
$36.7 million of investor capital raised transferred by our Predecessor to the Atlas Eagle Ford 2015 L.P. private drilling partnership for activities directly related to their program; and
|
|
|
•
|
|
$5.2 million of funds transferred to certain Drilling Partnerships.
|
Cash Flows From Investing
Activities:
Successor Nine Months Ended September 30, 2017
|
|
•
|
|
consists of $109.1 million in net cash provided by continuing investing activities for the sale of our Rangely Assets; and
|
|
|
•
|
|
$77.0 million in net proceeds from discontinued operations for the majority of the sale of our Appalachian Assets; partially offset by
|
|
|
•
|
|
$37.2 million in capital expenditures paid related to our drilling activities.
|
Successor Period from September 1, 2016 through September 30, 2016
|
|
•
|
|
$5.4 million in capital expenditures paid related to our drilling activities.
|
Predecessor Period from January 1, 2016 through August 31, 2016
|
|
•
|
|
$24.9 million in capital expenditures paid related to our Predecessor’s drilling activities.
|
Cash Flows From Financing Activities:
Successor Nine Months Ended September 30, 2017
|
|
•
|
|
consists of $179.5 million in repayments under our First Lien Credit Facility; and
|
|
|
•
|
|
$1.0 million in deferred financing costs primarily related to our First Lien Credit Facility amendments.
|
Predecessor Period from January 1, 2016 through August 31, 2016
|
|
•
|
|
consists of $156.2 million in net repayments on our Predecessor’s revolving credit facility;
|
|
|
•
|
|
$12.6 million in distributions paid to our Predecessor’s unitholders;
|
|
|
•
|
|
$8.0 million in deferred financing costs primarily related to our Predecessor’s revolving credit facility; and
|
|
|
•
|
|
$5.5 million related to our Predecessor’s senior note repurchases.
|
47
Capital Requirements
At September 30, 2017, the capital expenditures of our natural gas and oil production assets primarily consist of discretionary
expenditures to maintain or increase production margin in future periods, as well as land, gathering and processing, and other
non-drilling
capital expenditures.
As of September 30, 2017, we are committed to expend approximately $2.8 million on a new enterprise resource planning system and
drilling and completion and other capital expenditures. We expect to fund these capital expenditure commitments with our cash flows from operations.
OFF BALANCE SHEET ARRANGEMENTS
As of
September 30, 2017, our
off-balance
sheet arrangements were limited to our letters of credit outstanding of $2.8 million and commitments to spend $2.8 million related to a new enterprise
resource planning system and our drilling and completion and capital expenditures.
CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS
There have been no material changes to our contractual obligations and commercial commitments from those disclosed in our Annual Report on Form
10-K
for the fiscal year ended December 31, 2016, except for our well drilling and completion commitments is $0.4 million as of September 30, 2017 as compared to $19.4 million as of
December 31, 2016, and our commitments for a new enterprise resource planning system of $1.9 million at September 30, 2017 as compared to zero as of December 31, 2016.
CREDIT FACILITIES
First Lien Credit Facility
On September 1, 2016, we entered into our $440 million First Lien Credit Facility with Wells Fargo Bank, National Association, as
administrative agent, and the lenders party thereto. See Note 5 to our condensed consolidated financial statements for a summary of the key provisions of our First Lien Credit Facility and subsequent amendments.
Second Lien Credit Facility
On
September 1, 2016, we entered into our Second Lien Credit Facility with Wilmington Trust, National Association, as administrative agent, and the lenders party thereto for an aggregate principal amount of $252.5 million. See Note 5 to our
condensed consolidated financial statements for a summary of the key provisions of our Second Lien Credit Facility and subsequent amendments.
CRITICAL
ACCOUNTING POLICIES AND ESTIMATES
For a more complete discussion of the accounting policies and estimates that we have identified as
critical in the preparation of our condensed consolidated financial statements, please refer to our Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form
10-K
for the fiscal year ended December 31, 2016.
Recently Issued Accounting Standards
See Note 2 to our condensed consolidated financial statements for additional information related to recently issued accounting standards.
|
ITEM 3:
|
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
|
The primary objective of the
following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in interest rates and
commodity prices. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonable possible losses. This forward-looking information provides indicators of how we view and manage our ongoing
market risk exposures. All of the market risk-sensitive instruments were entered into for purposes other than trading.
We are exposed to
various market risks, principally fluctuating interest rates and changes in commodity prices. These risks can impact our results of operations, cash flows and financial position. We manage these risks through regular operating and financing
activities and periodic use of derivative financial instruments such as forward contracts and interest rate cap and swap agreements. The following analysis presents the effect on our results of operations as if the hypothetical changes in market
risk factors occurred on September 30, 2017. Only the potential impact of hypothetical assumptions was analyzed. The analysis does not consider other possible effects that could impact our business.
48
Interest Rate Risk
. At September 30, 2017, $256.3 million was outstanding under
our First Lien Credit Facility and $283.5 million was outstanding under our Second Lien Credit Facility. Holding all other variables constant, a hypothetical 1% change in variable interest rates would change our condensed consolidated interest
expense for the twelve-month period ending September 30, 2018 by approximately $5.4 million.
Commodity Price Risk
.
Holding all other variables constant, including the effect of commodity derivatives, a 10% change in average commodity prices would result in a change to our condensed consolidated operating income for the twelve-month period ending
September 30, 2018 of approximately $0.3 million.
At September 30, 2017, we had the following commodity derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Type
|
|
Production
Period Ending
December 31,
|
|
|
Volumes
(1)
|
|
|
Average
Fixed Price
(1)
|
|
|
Natural Gas – Fixed Price Swaps
|
|
|
2017
|
(2)
|
|
|
12,919,900
|
|
|
$
|
3.140
|
|
|
|
|
|
2018
|
|
|
|
43,947,300
|
|
|
$
|
2.959
|
|
|
|
|
|
|
|
Crude Oil – Fixed Price Swaps
|
|
|
2017
|
(2)
|
|
|
196,500
|
|
|
$
|
47.441
|
|
|
|
|
|
2018
|
|
|
|
588,500
|
|
|
$
|
50.286
|
|
|
|
|
|
2019
|
|
|
|
73,000
|
|
|
|
|
|
|
(1)
|
Volumes for natural gas are stated in million British Thermal Units. Volumes for crude oil are stated in barrels.
|
|
(2)
|
The production volumes for 2017 include the remaining three months of 2017 beginning October 1, 2017.
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ITEM 4:
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CONTROLS AND PROCEDURES
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Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Securities
Exchange Act of 1934 reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief
Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, our management recognized that any controls and procedures,
no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible
controls and procedures.
Under the supervision of our Chief Executive Officer and Chief Financial Officer and with the participation of
our disclosure committee appointed by such officers, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive
Officer and Chief Financial Officer concluded that, as of September 30, 2017, our disclosure controls and procedures were effective at the reasonable assurance level.
There have been no changes in our internal control over financial reporting during our most recent fiscal quarter that have materially
affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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