Item 2—Management’s Discussion and Analysis of Financial Condition and Results of Operations
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
We have made in this report, and may from time to time otherwise make in other public filings, press releases and discussions with our management, forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), concerning our operations, economic performance and financial condition. These forward-looking statements include information concerning future production and reserves, schedules, plans, timing of development, contributions from oil and natural gas properties, marketing and midstream activities, and also include those statements accompanied by or that otherwise include the words “may,” “could,” “believes,” “expects,” “anticipates,” “intends,” “estimates,” “projects,” “predicts,” “target,” “goal,” “plans,” “objective,” “potential,” “should,” or similar expressions or variations on such expressions that convey the uncertainty of future events or outcomes. For such statements, we claim the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. We have based these forward-looking statements on our current expectations and assumptions about future events. These statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct. These forward-looking statements speak only as of the date of this report, or if earlier, as of the date they were made; we undertake no obligation to publicly update or revise any forward-looking statements whether as a result of new information, future events or otherwise.
These forward-looking statements involve risk and uncertainties. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, the following:
|
|
•
|
the market prices of oil and natural gas;
|
|
|
•
|
volatility in the commodity-futures market;
|
|
|
•
|
financial market conditions and availability of capital;
|
|
|
•
|
future cash flows, credit availability and borrowings;
|
|
|
•
|
sources of funding for exploration and development;
|
|
|
•
|
our financial condition;
|
|
|
•
|
our ability to repay our debt;
|
|
|
•
|
the securities, capital or credit markets;
|
|
|
•
|
planned capital expenditures;
|
|
|
•
|
future drilling activity;
|
|
|
•
|
uncertainties about the estimated quantities of our oil and natural gas reserves;
|
|
|
•
|
pursuit of potential future acquisition opportunities;
|
|
|
•
|
general economic conditions, either nationally or in the jurisdictions in which we are doing business;
|
|
|
•
|
legislative or regulatory changes, including retroactive royalty or production tax regimes, hydraulic-fracturing regulation, drilling and permitting regulations, derivatives reform, changes in state and federal corporate taxes, environmental regulation, environmental risks and liability under federal, state and foreign and local environmental laws and regulations;
|
|
|
•
|
the creditworthiness of our financial counter-parties and operation partners; and
|
|
|
•
|
other factors discussed below and elsewhere in this Quarterly Report on Form 10-Q and in our other public filings, press releases and discussions with our management.
|
For additional information regarding known material factors that could cause our actual results to differ from projected results please read the rest of this report and Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2018.
Overview
Goodrich Petroleum Corporation (“Goodrich” and, together with its subsidiary, Goodrich Petroleum Company, L.L.C. (the "Subsidiary”), “we,” “our,” or the “Company”) is an independent oil and natural gas company engaged in the exploration, development and production of oil and natural gas on properties primarily in (i) Northwest Louisiana and East Texas, which includes the Haynesville Shale Trend, (ii) Southwest Mississippi and Southeast Louisiana, which includes the Tuscaloosa Marine Shale Trend (“TMS”), and (iii) South Texas, which includes the Eagle Ford Shale Trend.
We seek to increase shareholder value by growing our oil and natural gas reserves, production, revenues and cash flow from operating activities (“operating cash flow”). In our opinion, on a long term basis, growth in oil and natural gas reserves, cash flow and production on a cost-effective basis are the most important indicators of performance success for an independent oil and natural gas company.
We strive to increase our oil and natural gas reserves, production and cash flow through exploration and development activities. We develop an annual capital expenditure budget, which is reviewed and approved by our Board of Directors (the “Board”) on a quarterly basis and revised throughout the year as circumstances warrant. We take into consideration our projected operating cash flow, commodity prices for oil and natural gas and externally available sources of financing, such as bank debt, asset divestitures, issuance of debt and equity securities, and strategic joint ventures, when establishing our capital expenditure budget.
We place primary emphasis on our operating cash flow in managing our business. Management considers operating cash flow a more important indicator of our financial success than other traditional performance measures such as net income because operating cash flow considers only the cash expenses incurred during the period and excludes the non-cash impact of unrealized hedging gains (losses), non-cash general and administrative expenses and impairments.
Our revenues and operating cash flow depend on the successful development of our inventory of capital projects with available capital, the volume and timing of our production, as well as commodity prices for oil and natural gas. Such pricing factors are largely beyond our control; however, we employ commodity hedging techniques in an attempt to minimize the volatility of short term commodity price fluctuations on our earnings and operating cash flow.
Primary Operating Areas
Haynesville Shale Trend
Our relatively low risk development acreage in this trend is primarily centered in Caddo, DeSoto and Red River parishes, Louisiana and Angelina and Nacogdoches counties, Texas. We have acquired or farmed-in leases totaling approximately 38,000 gross (22,000 net) acres as of September 30, 2019 in the Haynesville Shale Trend. We completed and produced 1 gross (0.9 net) new well in the third quarter of 2019 and had 6 gross (3.4 net) wells in the drilling or completions phase as of September 30, 2019. Our net production volumes from our Haynesville Shale Trend wells represented approximately 98% of our total equivalent production on a Mcfe basis and substantially all of our natural gas production for the third quarter of 2019. We are focusing on increasing our natural gas production volumes through increased drilling in the Haynesville Shale Trend, where we plan to focus all of our remaining 2019 drilling efforts.
Tuscaloosa Marine Shale Trend
We have acquired approximately 48,000 gross (33,000 net) lease acres in the TMS as of September 30, 2019 with approximately 46,000 gross (32,000 net) acres held by production. We have 2 gross (1.7 net) TMS wells drilled and awaiting completion. Our net production volumes from our TMS wells represented approximately 2% of our total equivalent production on a Mcfe basis and substantially all of our total oil production for the third quarter of 2019. Despite no capital expenditures, we are seeking to maintain production through strategic expense workover operations in the TMS.
Eagle Ford Shale Trend
We have retained approximately 12,000 net acres of undeveloped leasehold in the Eagle Ford Shale Trend in Frio County, Texas as of September 30, 2019, which is prospective for future development or sale.
Results of Operations
The item that had the most material financial effect on our net income of $2.0 million for the three months ended September 30, 2019 was a $3.8 million gain on derivatives not designated as hedges. The majority of the gain was attributable to settlement of our natural gas derivative positions at prices lower than our fixed contract prices. The items that had the most material financial effect on our net income of $14.2 million for the nine months ended September 30, 2019, in addition to derivative settlement and mark-to-market gains, were oil and gas revenues, transportation and processing expense and depletion, depreciation and amortization expense. All these items increased compared to the nine months ended September 30, 2018, which is primarily attributable to production volume increases.
The Company recorded net income of $1.7 million for the three months ended September 30, 2018 and a net loss of $6.3 million for nine months ended September 30, 2018. The items that had the most material financial effect on our net loss of $6.3 million for the nine months ended September 30, 2018 were a $3.4 million loss on our commodity derivatives not designated as hedges, $4.7 million share-based compensation included in general and administrative expense and $8.5 million in interest expense. All but $1.3 million of these items are non-cash expenses.
We recognized operating income in each period presented due to our increasing revenues attributed to increased production volumes.
The following table reflects our summary operating information for the periods presented (in thousands, except for price and volume data). Because of normal production declines, increased or decreased drilling activity and the effects of acquisitions or divestitures, the historical information presented below should not be interpreted as indicative of future results.
Revenues from Operations
|
|
|
Three Months Ended September 30,
|
|
|
Nine Months Ended September 30,
|
|
|
(In thousands, except for price and average daily production data)
|
|
2019
|
|
|
2018
|
|
|
Variance
|
|
|
2019
|
|
|
2018
|
|
|
Variance
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
|
|
$
|
24,684
|
|
|
$
|
20,572
|
|
|
$
|
4,112
|
|
|
|
20
|
%
|
|
$
|
79,986
|
|
|
$
|
42,289
|
|
|
$
|
37,697
|
|
|
|
89
|
%
|
|
Oil and condensate
|
|
|
2,477
|
|
|
|
3,759
|
|
|
|
(1,282
|
)
|
|
|
(34
|
)%
|
|
|
8,207
|
|
|
|
11,669
|
|
|
|
(3,462
|
)
|
|
|
(30
|
)%
|
|
Natural gas, oil and condensate
|
|
|
27,161
|
|
|
|
24,331
|
|
|
|
2,830
|
|
|
|
12
|
%
|
|
|
88,193
|
|
|
|
53,958
|
|
|
|
34,235
|
|
|
|
63
|
%
|
|
Net Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Mmcf)
|
|
|
12,257
|
|
|
|
7,479
|
|
|
|
4,778
|
|
|
|
64
|
%
|
|
|
33,622
|
|
|
|
15,601
|
|
|
|
18,021
|
|
|
|
116
|
%
|
|
Oil and condensate (MBbls)
|
|
|
42
|
|
|
|
52
|
|
|
|
(10
|
)
|
|
|
(19
|
)%
|
|
|
134
|
|
|
|
169
|
|
|
|
(35
|
)
|
|
|
(21
|
)%
|
|
Total (Mmcfe)
|
|
|
12,506
|
|
|
|
7,789
|
|
|
|
4,717
|
|
|
|
61
|
%
|
|
|
34,425
|
|
|
|
16,617
|
|
|
|
17,808
|
|
|
|
107
|
%
|
|
Average daily production (Mcfe/d)
|
|
|
135,936
|
|
|
|
84,663
|
|
|
|
51,273
|
|
|
|
61
|
%
|
|
|
126,097
|
|
|
|
60,868
|
|
|
|
65,229
|
|
|
|
107
|
%
|
|
Average realized sales price per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
2.01
|
|
|
$
|
2.75
|
|
|
$
|
(0.74
|
)
|
|
|
(27
|
)%
|
|
$
|
2.38
|
|
|
$
|
2.71
|
|
|
$
|
(0.33
|
)
|
|
|
(12
|
)%
|
|
Natural gas (per Mcf) including the effect of realized gains/losses on derivatives
|
|
$
|
2.51
|
|
|
$
|
2.80
|
|
|
$
|
(0.29
|
)
|
|
|
(10
|
)%
|
|
$
|
2.58
|
|
|
$
|
2.77
|
|
|
$
|
(0.19
|
)
|
|
|
(7
|
)%
|
|
Oil and condensate (per Bbl)
|
|
$
|
59.67
|
|
|
$
|
72.29
|
|
|
$
|
(12.62
|
)
|
|
|
(17
|
)%
|
|
$
|
61.40
|
|
|
$
|
69.05
|
|
|
$
|
(7.65
|
)
|
|
|
(11
|
)%
|
|
Oil and condensate (per Bbl) including the effect of realized losses on derivatives
|
|
$
|
56.09
|
|
|
$
|
61.37
|
|
|
$
|
(5.28
|
)
|
|
|
(9
|
)%
|
|
$
|
57.52
|
|
|
$
|
59.25
|
|
|
$
|
(1.73
|
)
|
|
|
(3
|
)%
|
|
Average realized price (per Mcfe)
|
|
$
|
2.17
|
|
|
$
|
3.12
|
|
|
$
|
(0.95
|
)
|
|
|
(30
|
)%
|
|
$
|
2.56
|
|
|
$
|
3.25
|
|
|
$
|
(0.69
|
)
|
|
|
(21
|
)%
|
Natural gas, oil and condensate revenues increased by $2.8 million and $34.2 million, respectively for the three and nine months ended September 30, 2019 compared to the same periods in 2018. The increase was primarily driven by increased natural gas production offset by lower realized commodity prices and decreased oil production. The increase in natural gas production volumes is attributed to one operated Haynesville Shale Trend well completed in the third quarter of 2019 and the continued production of an additional eight operated and six non-operated Haynesville Shale Trend wells completed since the third quarter of 2018. We have brought 8 gross (6.0 net) Haynesville Trend wells on production since September 30, 2018. For the three and nine months ended September 30, 2019, 91% of our oil and natural gas revenue was attributable to natural gas sales compared to 85% and 78%, respectively for the three and nine months ended September 30, 2018.
Operating Expenses
As described below, total operating expenses increased $7.6 million to $26.9 million for the three months ended September 30, 2019 and increased $30.2 million to $78.5 million for the nine months ended September 30, 2019, compared to the same periods in 2018. The increase in total operating expenses for the three and nine months ended September 30, 2019 was primarily due to the increase in the number of producing wells and an increase in depreciation, depletion and amortization and transportation expense discussed further below.
|
|
|
Three Months Ended September 30,
|
|
|
Nine Months Ended September 30,
|
|
|
Operating Expenses (in thousands)
|
|
2019
|
|
|
2018
|
|
|
Variance
|
|
|
2019
|
|
|
2018
|
|
|
Variance
|
|
|
Lease operating expenses
|
|
$
|
2,589
|
|
|
$
|
2,588
|
|
|
$
|
1
|
|
|
|
0
|
%
|
|
$
|
8,902
|
|
|
$
|
7,619
|
|
|
$
|
1,283
|
|
|
|
17
|
%
|
|
Production and other taxes
|
|
|
623
|
|
|
|
959
|
|
|
|
(336
|
)
|
|
|
(35
|
)%
|
|
|
1,878
|
|
|
|
2,268
|
|
|
|
(390
|
)
|
|
|
(17
|
)%
|
|
Transportation and processing
|
|
|
5,107
|
|
|
|
3,344
|
|
|
|
1,763
|
|
|
|
53
|
%
|
|
|
15,562
|
|
|
|
6,742
|
|
|
|
8,820
|
|
|
|
131
|
%
|
|
Operating Expenses per Mcfe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
0.21
|
|
|
$
|
0.33
|
|
|
$
|
(0.12
|
)
|
|
|
(36
|
)%
|
|
$
|
0.26
|
|
|
$
|
0.46
|
|
|
$
|
(0.20
|
)
|
|
|
(43
|
)%
|
|
Production and other taxes
|
|
$
|
0.05
|
|
|
$
|
0.12
|
|
|
$
|
(0.07
|
)
|
|
|
(58
|
)%
|
|
$
|
0.05
|
|
|
$
|
0.14
|
|
|
$
|
(0.09
|
)
|
|
|
(64
|
)%
|
|
Transportation and processing
|
|
$
|
0.41
|
|
|
$
|
0.43
|
|
|
$
|
(0.02
|
)
|
|
|
(5
|
)%
|
|
$
|
0.45
|
|
|
$
|
0.41
|
|
|
$
|
0.04
|
|
|
|
10
|
%
|
Lease Operating Expense
Lease operating expense (“LOE”) remaining steady at $2.6 million and increased $1.3 million to $8.9 million, respectively, during the three and nine months ended September 30, 2019 compared to the same periods in 2018. The increase in LOE between years was totally attributable to increased production volumes which increased variable lease operating costs such as saltwater disposal and equipment rental expenses while fixed expenses remained relatively the same between periods. The per unit cost of production has been driven down to $0.21 per mcfe and $0.26 per mcfe, respectively, for the three and nine months ended September 30, 2019. Per unit LOE is expected to continue to decrease as we increase production in the Haynesville Shale Trend, which carries a much lower per unit LOE than the Company’s current per unit rate.
Production and Other Taxes
Production and other taxes includes severance and ad valorem taxes. Severance taxes were $0.4 million and $1.1 million respectively for the three and nine months ended September 30, 2019, which decreased by $0.4 million from the same periods in 2018. Severance taxes in 2018 were higher due to a non-recurring tax rate true-up associated with our non-operated take-in-kind natural gas volumes. Ad valorem taxes were $0.2 million and $0.8 million, respectively, for the three and nine months ended September 30, 2019, which was relatively unchanged from the same periods in 2018. The State of Louisiana has enacted an exemption from the existing 12.5% severance tax on oil and from the $0.111 per Mcf (from July 1, 2017 through June 30, 2018), $0.122 per Mcf (from July 1, 2018 through June 30, 2019) and $0.125 per Mcf (which began on July 1, 2019) severance tax on natural gas for horizontal wells with production commencing after July 31, 1994. The exemption is applicable until the earlier of (i) 24 months from the date of first sale of production or (ii) payout of the well. Our recently drilled Haynesville Shale Trend wells in Northwest Louisiana are benefiting from this exemption. Though ad valorem tax remained relatively unchanged between the periods presented, we expect ad valorem taxes to increase as our newly producing wells begin to be valued by the taxing jurisdictions.
Transportation and Processing
Transportation and processing expense for the three and nine months ended September 30, 2019 increased compared to the same periods in 2018, reflecting increased production from our Haynesville Shale Trend wells. Our natural gas volumes from our operated wells generally carry less transportation cost per Mcf than wells we do not operate. Despite an increase in our operated natural gas production volumes between years, our cost per Mcfe decreased for the three months but increased for the three and nine months ended September 30, 2019 compared to 2018. This per unit increase for the nine months ended September 30, 2019 is partially attributed to the mix of oil and natural gas production volumes during the year as our oil production is decreasing and not burdened by transportation and processing cost. Additionally, the wells we have recently put on production are producing from leases that stipulate that the royalty is free from transportation cost; consequently, we currently are incurring a proportionately higher transportation cost on the production from those wells.
|
|
|
Three Months Ended September 30,
|
|
|
Nine Months Ended September 30,
|
|
|
Operating Expenses (in thousands):
|
|
2019
|
|
|
2018
|
|
|
Variance
|
|
|
2019
|
|
|
2018
|
|
|
Variance
|
|
|
Depreciation, depletion and amortization
|
|
$
|
13,205
|
|
|
$
|
7,922
|
|
|
$
|
5,282
|
|
|
|
67
|
%
|
|
$
|
36,550
|
|
|
$
|
16,934
|
|
|
$
|
19,616
|
|
|
|
116
|
%
|
|
General and administrative
|
|
|
5,196
|
|
|
|
4,644
|
|
|
|
552
|
|
|
|
12
|
%
|
|
|
15,442
|
|
|
|
14,643
|
|
|
|
799
|
|
|
|
5
|
%
|
|
Other
|
|
|
228
|
|
|
|
(60
|
)
|
|
|
288
|
|
|
|
480
|
%
|
|
|
179
|
|
|
|
105
|
|
|
|
74
|
|
|
|
70
|
%
|
|
Operating Expenses per Mcfe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
$
|
1.06
|
|
|
$
|
1.02
|
|
|
$
|
0.04
|
|
|
|
4
|
%
|
|
$
|
1.06
|
|
|
$
|
1.02
|
|
|
$
|
0.04
|
|
|
|
4
|
%
|
|
General and administrative
|
|
$
|
0.42
|
|
|
$
|
0.60
|
|
|
$
|
(0.18
|
)
|
|
|
(30
|
)%
|
|
$
|
0.45
|
|
|
$
|
0.88
|
|
|
$
|
(0.43
|
)
|
|
|
(49
|
)%
|
|
Other
|
|
$
|
0.02
|
|
|
$
|
(0.01
|
)
|
|
$
|
0.03
|
|
|
|
300
|
%
|
|
$
|
0.01
|
|
|
$
|
0.01
|
|
|
$
|
-
|
|
|
|
0
|
%
|
Depreciation, Depletion and Amortization (“DD&A”)
DD&A expense is calculated on the Full Cost Method using the units of production (the “UOP”) method. The increase in DD&A expense was attributed primarily to increased production as well as an increased DD&A rate for the three and nine months ended September 30, 2019 as compared to the same period in 2018. The increased rate takes into account the estimated future cost of drilling and completing wells.
General and Administrative (“G&A”)
The Company recorded $5.2 million and $15.4 million respectively in G&A expense for the three and nine months ended September 30, 2019, which is an increase of $0.6 million and $0.8 million, respectively, compared to the same periods in 2018. G&A expense for 2019 included increased compensation expense and increased directors costs related to the increase in number of directors on our board of directors. We also incurred increased legal fees in 2019 due to preparation of the Notice of Stockholder Action by Written Consent and preparation of the annual Proxy, which provided for changes to the Original Certificate of Incorporation. The Written Consent and Proxy were filed with the Securities and Exchange Commission on June 24, 2019 and July 19, 2019, respectively. G&A expense for the three and nine months ended September 30, 2019 included non-cash expenses of $1.6 million and $4.7 million, respectively, for share-based compensation, which is virtually unchanged from the same periods in 2018.
Other Income (Expense)
|
|
|
Three Months Ended September 30,
|
|
|
Nine Months Ended September 30,
|
|
|
Other income (expense) (in thousands):
|
|
2019
|
|
|
2018
|
|
|
Variance
|
|
|
2019
|
|
|
2018
|
|
|
Variance
|
|
|
Interest expense
|
|
$
|
(1,981
|
)
|
|
$
|
(3,105
|
)
|
|
$
|
1,124
|
|
|
|
(36
|
)%
|
|
$
|
(9,036
|
)
|
|
$
|
(8,510
|
)
|
|
$
|
(526
|
)
|
|
|
6
|
%
|
|
Interest income and other
|
|
|
-
|
|
|
|
1
|
|
|
|
(1
|
)
|
|
|
(100
|
)%
|
|
|
24
|
|
|
|
110
|
|
|
|
(86
|
)
|
|
|
(78
|
)%
|
|
Gain (loss) on commodity derivatives not designated as hedges
|
|
|
3,752
|
|
|
|
(237
|
)
|
|
|
3,989
|
|
|
|
1683
|
%
|
|
|
15,397
|
|
|
|
(3,392
|
)
|
|
|
18,789
|
|
|
|
554
|
%
|
|
Loss on early extinguishment of debt
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
0
|
%
|
|
|
(1,846
|
)
|
|
|
-
|
|
|
|
(1,846
|
)
|
|
|
(100
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average funded borrowings adjusted for debt discount
|
|
$
|
95,761
|
|
|
$
|
58,196
|
|
|
$
|
37,565
|
|
|
|
65
|
%
|
|
$
|
92,641
|
|
|
$
|
51,077
|
|
|
$
|
41,564
|
|
|
|
81
|
%
|
|
Average funded borrowings
|
|
$
|
99,598
|
|
|
$
|
63,206
|
|
|
$
|
36,392
|
|
|
|
58
|
%
|
|
$
|
96,323
|
|
|
$
|
57,568
|
|
|
$
|
38,755
|
|
|
|
67
|
%
|
Interest Expense
Interest expense for the three and nine months ended September 30, 2019 reflected interest payable in cash of $1.2 million and $2.7 million, respectively, incurred on the 2017 Senior Credit Facility and 2019 Senior Credit Facility and non-cash interest of $0.7 million and $6.3 million, respectively, incurred primarily on the Company's Convertible Second Lien Notes and New 2L Notes, which included $0.4 million and $3.6 million, respectively, of paid in-kind interest and $0.3 million and $2.8 million, respectively, of debt discount and debt issuance cost amortization.
Interest expense for the three and nine months ended September 30, 2018 reflected cash interest of $0.3 million and $0.5 million, respectively, incurred on the 2017 Senior Credit Facility and non-cash interest of $2.8 million and $8.0 million, respectively, incurred on the Company's Convertible Second Lien Notes, which included $1.7 million and $4.9 million, respectively, of paid in-kind interest and $1.1 million and $2.9 million, respectively, of debt discount and debt issuance cost amortization.
Interest expense increased in the 2019 periods presented compared to the same periods in 2018 due to increased funded debt, mainly resulting from the accretion of the paid in-kind interest on our Convertible Second Lien Notes. On May 29, 2019, we redeemed our Convertible Second Lien Notes using borrowings from our 2019 Senior Credit Facility and recorded a $1.8 million loss on early extinguishment of debt. On May 31, 2019, we issued $12.0 million of new convertible second lien notes. The result of these transactions going forward will result in the Company incurring less interest expense overall but an increase in interest payable in cash.
Gain (Loss) on Commodity Derivatives Not Designated as Hedges
Gain on commodity derivatives not designated as hedges for the three months ended September 30, 2019 was comprised of $5.9 million gain on cash settlements during the period offset by a mark-to-market loss of $2.2 million, representing the change of the fair value of our natural gas derivative contracts from June 30, 2019. Gain on commodity derivatives not designated as hedges for the nine months ended September 30, 2019 was comprised of a mark-to-market gain of $9.3 million, representing the change of the fair value of our natural gas derivative contracts from December 31, 2018, and a $6.1 million gain on net cash settlements during the period. Natural gas futures prices continued to fall below our fixed contract prices in the third quarter of 2019 resulting in our derivative asset position. Since we do not apply hedge accounting on our derivatives contracts there can be large swings in our reported gain or losses between periods. Going forward, any increase in natural gas futures prices would result in recording of losses in future periods.
Loss on commodity derivatives not designated as hedges for the three and nine months ended September 30, 2018 was comprised of a mark-to-market loss of $0.1 million and $2.7 million, respectively, representing the change of the fair value of our open natural gas and oil derivative contracts, as well as a loss of $0.2 million and $0.7 million, respectively, on cash settlements of natural gas and oil derivative contracts.
Income Tax Benefit
We recorded no income tax expense or benefit for the three or nine months ended September 30, 2019. We recorded a valuation allowance for our net deferred tax asset at December 31, 2016. We recorded this valuation allowance at this date after an evaluation of all available evidence (including our history of net operating losses) that led to a conclusion that based upon the more-likely-than-not standard of the accounting literature, these deferred tax assets were unrecoverable.
The valuation allowance was $84.1 million as of December 31, 2018, which resulted in a net non-current deferred tax asset of $0.8 million appearing on our statement of financial position as of December 31, 2018. The net $0.8 million deferred tax asset related to Alternative Minimum Tax (“AMT”) credits, which are expected to be fully refundable in tax years 2018 - 2021 regardless of the Company's regular tax liability. During the three months ended September 30, 2019, the Company reclassed $0.4 million from the deferred tax asset to accounts receivable representing the refund we expect to receive in connection with the monetization of the AMT credits in tax year 2018 leaving the remaining $0.4 million recorded as a deferred tax asset as of September 30, 2019. Considering the Company’s taxable income forecasts, our assessment of the realization of our deferred tax assets has not changed, and we continue to maintain a full valuation allowance for our net deferred tax assets as of September 30, 2019 aside from the deferred tax asset related to the AMT credits.
Adjusted EBITDA
Adjusted EBITDA is a supplemental non-United States Generally Accepted Accounting Principle (“US GAAP”) financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines Adjusted EBITDA as earnings before interest expense, income and similar tax, DD&A, share-based compensation expense and impairment of oil and natural gas properties (if any). In calculating Adjusted EBITDA, gains/losses on reorganization and mark-to-market gains/losses on commodity derivatives not designated as hedges are also excluded. Other excluded items include adjustments resulting from the accounting for operating leases under Accounting Standards Codification (“ASC”) 842, interest income and any extraordinary non-cash gains or losses. Adjusted EBITDA is not a measure of net income (loss) as determined by US GAAP. Adjusted EBITDA should not be considered an alternative to net income (loss), as defined by US GAAP.
The following table presents a reconciliation of the non-US GAAP measure of Adjusted EBITDA to the US GAAP measure of net income (loss), its most directly comparable measure presented in accordance with US GAAP:
|
|
|
Three Months Ended September 30,
|
|
|
Nine Months Ended September 30,
|
|
|
(In thousands)
|
|
2019
|
|
|
2018
|
|
|
2019
|
|
|
2018
|
|
|
Net income (loss) (US GAAP)
|
|
$
|
1,988
|
|
|
$
|
1,666
|
|
|
$
|
14,215
|
|
|
$
|
(6,319
|
)
|
|
Interest expense
|
|
|
1,981
|
|
|
|
3,105
|
|
|
|
9,036
|
|
|
|
8,510
|
|
|
Depreciation, depletion and amortization
|
|
|
13,205
|
|
|
|
7,922
|
|
|
|
36,550
|
|
|
|
16,934
|
|
|
Share-based compensation expense (non-cash)
|
|
|
1,617
|
|
|
|
1,597
|
|
|
|
4,765
|
|
|
|
4,763
|
|
|
(Gain) loss on commodity derivatives not designated as hedges, not settled
|
|
|
2,170
|
|
|
|
41
|
|
|
|
(9,262
|
)
|
|
|
2,655
|
|
|
Loss on early extinguishment of debt
|
|
|
-
|
|
|
|
-
|
|
|
|
1,846
|
|
|
|
-
|
|
|
Other items (1)
|
|
|
297
|
|
|
|
(45
|
)
|
|
|
855
|
|
|
|
54
|
|
|
Adjusted EBITDA
|
|
$
|
21,258
|
|
|
$
|
14,286
|
|
|
$
|
58,005
|
|
|
$
|
26,597
|
|
|
(1)
|
Other items include $0.3 million, zero, $0.9 million and zero, respectively, from the impact of accounting for operating leases under ASC 842 as well as interest income, reorganization items and other non-recurring income and expense.
|
Management believes that this non-US GAAP financial measure provides useful information to investors because it is monitored and used by our management and widely used by professional research analysts in the valuation and investment recommendations of companies within the oil and natural gas exploration and production industry.
Liquidity and Capital Resources
Overview
Our primary sources of cash during the first nine months of 2019 were cash on hand, cash from operating activities, net proceeds from borrowings on our senior credit facilities and proceeds from the sale of assets. We used cash primarily to fund capital expenditures. We currently plan to fund our operations and capital expenditures for the remainder of 2019 through a combination of cash on hand, cash from operating activities and borrowings under the 2019 Senior Credit Facility, although we may from time to time consider the funding alternatives described below.
On May 14, 2019, the Company entered into a Second Amended and Restated Senior Secured Revolving Credit Agreement (the “2019 Credit Agreement”) among the Company, the Subsidiary, as borrower (in such capacity, the “Borrower”), SunTrust Bank, as administrative agent (the “Administrative Agent”), and certain lenders that are party thereto, which provides for revolving loans of up to the borrowing base then in effect (the “2019 Senior Credit Facility”). The 2019 Senior Credit Facility amends, restates and refinances the obligations under our 2017 Credit Agreement.
The 2019 Senior Credit Facility matures (a) May 14, 2024 or (b) the date that is 180 days prior to the “Maturity Date” as defined in the indenture governing the New 2L Notes (the “New 2L Notes Indenture”) as in effect on the issuance date of the New 2L Notes if the New 2L Notes (as defined below) have not been voluntarily redeemed, repurchased, refinanced or otherwise retired by such date. The maximum credit amount under the 2019 Senior Credit Facility is $500 million with a current borrowing base of $125 million. The borrowing base is scheduled to be redetermined in March and September of each calendar year, and is subject to additional adjustments from time to time, including for asset sales, elimination or reduction of hedge positions and incurrence of other debt. Additionally, each of the Borrower and the Administrative Agent may request one unscheduled redetermination of the borrowing base between scheduled redeterminations. The amount of the borrowing base is determined by the lenders at their sole discretion and consistent with their oil and gas lending criteria at the time of the relevant redetermination. The Borrower may also request the issuance of letters of credit under the 2019 Credit Agreement in an aggregate amount up to $10 million, which reduce the amount of available borrowings under the borrowing base in the amount of such issued and outstanding letters of credit.
On May 14, 2019, the Company and the Subsidiary entered into a purchase agreement with certain funds and accounts managed by Franklin Advisers, Inc., as investment manager (each such fund or account, together with its successors and assigns, a “New 2L Notes Purchaser”) pursuant to which the Company issued to the New 2L Notes Purchasers (the “New 2L Notes Offering”) $12.0 million aggregate principal amount of the Company’s 13.50% Convertible Second Lien Senior Secured Notes due 2021 (the “New 2L Notes”). The closing of the New 2L Notes Offering occurred on May 31, 2019. Proceeds from the sale of the New 2L Notes were primarily used to pay down outstanding borrowings under the 2019 Senior Credit Facility. Holders of the New 2L Notes have a second priority lien on all assets of the Company.
The New 2L Notes, as set forth in the New 2L Notes Indenture, are scheduled to mature on May 31, 2021. The New 2L Notes bear interest at the rate of 13.50% per annum, payable quarterly in arrears on January 15, April 15, July 15 and October 15 of each year. The Company may elect to pay all or any portion of interest in-kind on the then outstanding principal amount of the New 2L Notes by increasing the principal amount of the outstanding New 2L Notes.
We exited the third quarter of 2019 with $1.2 million of cash on hand and $87.9 million of outstanding borrowings with $37.1 million of availability under the 2019 Senior Credit Facility borrowing base. Due to the timing of payment of our capital expenditures, we reflected a working capital deficit of $23.8 million as of September 30, 2019. To the extent we operate with a working capital deficit, we expect such deficit to be offset by liquidity available under our 2019 Senior Credit Facility.
We continuously monitor our leverage position and coordinate our capital program with our expected cash flows and repayment of our projected debt. We will continue to evaluate funding alternatives as needed.
Alternatives available to us include:
|
|
•
|
availability under the 2019 Senior Credit Facility;
|
|
|
•
|
issuance of debt securities;
|
|
|
•
|
joint ventures in our TMS and/or Haynesville Shale Trend acreage;
|
|
|
•
|
sale of non-core assets; and
|
|
|
•
|
issuance of equity securities if favorable conditions exist.
|
We have supported our cash flows with derivative contracts that covered approximately 76% of our natural gas sales volumes for the first nine months of 2019 and 65% of our oil volumes for the first nine months of 2019. For additional information on our derivative instruments see Note 8—“Commodity Derivative Activities” in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
Cash Flows
The following table summarizes our cash flows for the periods indicated (in thousands):
|
|
|
Three Months Ended September 30,
|
|
|
Nine Months Ended September 30,
|
|
|
|
|
2019
|
|
|
2018
|
|
|
2019
|
|
|
2018
|
|
|
Cash flow statement information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provided by operating activities
|
|
$
|
15,594
|
|
|
$
|
24,080
|
|
|
$
|
56,847
|
|
|
$
|
36,735
|
|
|
Used in investing activities
|
|
|
(19,083
|
)
|
|
|
(32,005
|
)
|
|
|
(72,865
|
)
|
|
|
(58,185
|
)
|
|
Provided by (used in) financing activities
|
|
|
2,980
|
|
|
|
8,127
|
|
|
|
13,110
|
|
|
|
(2,611
|
)
|
|
Decrease in cash and cash equivalents
|
|
$
|
(509
|
)
|
|
$
|
202
|
|
|
$
|
(2,908
|
)
|
|
$
|
(24,061
|
)
|
Operating activities: Production from our wells, the price of oil and natural gas and operating costs represent the main drivers behind our cash flow from operations for the three and nine months ended September 30, 2019. Changes in working capital and net cash settlements related to our derivative contracts also impact cash flows. Net cash provided by operating activities for the three months ended September 30, 2019 was $15.6 million consisting of operating cash flows before working capital changes of $20.3 million reduced by negative working capital changes of $4.7 million. Net cash provided by operating activities for the three months ended September 30, 2019 was enhanced by $5.9 million net cash received from settled derivative contracts. Net cash provided by operating activities for the three months ended September 30, 2018 was $24.1 million including operating cash flows before working capital changes of $13.8 million reduced by net cash payments of $0.2 million in settlement of derivative contracts. Net cash provided by operating activities for the nine months ended September 30, 2019 was $56.8 million including operating cash flows before working capital changes of $55.7 million which included $6.1 million net cash received from settled derivative contracts. Net cash provided by operating activities for the nine months ended September 30, 2018 was $36.7 million including operating cash flows before working capital changes of $26.3 million reduced by net cash payments of $0.7 million in settlement of derivative contracts. Net cash provided by operating activities increased during the year to date period in 2019 compared to 2018 driven by revenue from production natural gas volume increases partially offset by lower realized commodity prices. The lower realized commodity prices were mitigated by our cash settled derivative contracts.
Investing activities: Net cash used in investing activities was $72.9 million for the nine months ended September 30, 2019. We paid out cash amounts totaling $74.2 million for drilling and development operations during the period versus recorded capital expenditures of $80.0 million. The difference in capital expenditures and cash expended on capital projects for the year was attributed to a net capital accrual increase of $5.1 million and $0.7 million of capitalized non-cash internal costs. The period also reflects the receipt of $1.3 million in proceeds from the sales of non-core oil and gas properties. We conducted drilling operations on 12 wells and completed 6 wells all in the Haynesville Shale Trend during the nine months ended September 30, 2019, capitalizing $2.7 million in internal costs. Net cash used in investing activities was $19.1 million for the three months ended September 30, 2019 which reflected cash expended on capital projects. We recorded $25.5 million in capital expenditures in this period. The difference in capital expenditures and cash expended on capital projects for the three months ended September 30, 2019 was attributed to a net capital accrual increase of $6.1 million and $0.3 million of capitalized non-cash internal costs.
Financing activities: Net cash provided by financing activities for the three and nine months ended September 30, 2019 reflects primarily net borrowings under our revolving credit facilities as well as the payoff of the Convertible Second Lien Notes and issuance of the New 2L Notes along with associated issuance costs paid in connection with such transactions.
Debt consisted of the following balances as of the dates indicated (in thousands):
|
|
|
September 30, 2019
|
|
|
December 31, 2018
|
|
|
|
|
Principal
|
|
|
Carrying Amount
|
|
|
Principal
|
|
|
Carrying Amount
|
|
|
2017 Senior Credit Facility
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
27,000
|
|
|
$
|
27,000
|
|
|
2019 Senior Credit Facility
|
|
|
87,900
|
|
|
|
87,900
|
|
|
|
-
|
|
|
|
-
|
|
|
Convertible Second Lien Notes (1)
|
|
|
-
|
|
|
|
-
|
|
|
|
53,691
|
|
|
|
49,820
|
|
|
New 2L Notes (2)
|
|
|
12,546
|
|
|
|
10,922
|
|
|
|
-
|
|
|
|
-
|
|
|
Total debt
|
|
$
|
100,446
|
|
|
$
|
98,822
|
|
|
$
|
80,691
|
|
|
$
|
76,820
|
|
(1) The debt discount was being amortized using the effective interest rate method based upon a maturity date of August 30, 2019 until the Convertible Second Lien Notes were fully paid off on May 29, 2019.
(2) The debt discount is being amortized using the effective interest rate method based upon a maturity date of May 31, 2021. The principal included $0.5 million of interest to be paid in-kind as of September 30, 2019. The carrying value included $1.3 million of unamortized debt discount as of September 30, 2019.
For additional information on our financing activities, see Note 4—“Debt” in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
Off-Balance Sheet Arrangements
We do not currently have any off-balance sheet arrangements for any purpose.
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition and results of operations are based on consolidated financial statements, which were prepared in accordance with US GAAP. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. We believe that certain accounting policies affect the more significant judgments and estimates used in the preparation of our consolidated financial statements. Our Annual Report on Form 10-K for the year ended December 31, 2018 includes a discussion of our critical accounting policies and there have been no material changes to such policies during the three months ended September 30, 2019.