Rex Energy Corporation (Nasdaq:REXX) today announced its third
quarter 2017 financial and operational results.
- In Butler Legacy, placed four-well Wilson pad into sales;
initial 24-hour average sales rate per well of ~10.9 MMcfe/d
- In Moraine East, the two-well Frye pad produced at an average
30-day sales rate per well of 8.5 MMcfe/d with 56% liquids
- Production volumes from the third quarter of 2017 were 182.0
MMcfe/d, including 38% from liquids
- Fourth quarter 2017 production expected to increase 10%
sequentially, at midpoint of guidance
- Realized C3+ NGL pricing, before cash-settled derivatives,
improved to $29.62/bbl in 3Q17 vs. $16.48/bbl in the prior year
quarter and was 61% of NYMEX
- Realized natural gas basis differential including the impact of
basis hedges improved to $(0.27)/mcf compared to $(1.15) last year,
a 77% improvement
- LOE per Mcfe to improve 5% - 10% in 4Q17 vs. 3Q17
- Commodity revenues, including cash-settled derivatives,
increased 29% during the third quarter of 2017, year-over-year
“The third quarter of 2017 was a very busy quarter
for Rex Energy, as we are nearing an inflection point for our
projected production and EBITDAX growth going into 4Q17,” said Tom
Stabley, President and Chief Executive Officer. “During the
quarter, we saw full utilization of our Gulf Coast transportation
and improved liquids pricing, leading to strong realizations for
both natural gas and C3+ production streams, a trend we see
continuing. Finally, with the continued high level of operational
activity during the fourth quarter, we anticipate that production
in our Butler Operated Area will continue to grow and allow us to
reach our targeted exit rates.”
Operational Update
Legacy Butler Operated Area
In the Legacy Butler Operated Area, the company
placed into sales the four-well Wilson pad. The four wells were
drilled to an average lateral length of approximately 9,300 feet
and were completed in an average of 51 stages. The four wells
produced at an initial 24-hour average sales rate per well,
assuming full ethane recovery, of 10.9 MMcfe/d, consisting of 6.6
MMcf/d of natural gas and 721 bbls/d of NGLs. The four wells have a
lower BTU rate than other areas of the Legacy Butler Operated Area,
but the timing of these wells being placed into sales and the
extended lateral lengths are expected to yield strong returns in
the current natural gas price environment.
Moraine East Area
In the Moraine East Area, the company drilled four
gross (four net) wells, completed six gross (3.4 net) wells and
placed into sales twelve gross (6.5 net) wells in the third quarter
of 2017. In addition, the company had seven gross (5.5 net) wells
awaiting completion at the end of the third quarter.
As previously reported, the company placed the
two-well Frye pad into sales during the third quarter. The two
wells produced at an average 24-hour sales rate per well, assuming
full ethane recovery, of 9.4 MMcfe/d. The two wells have gone on to
produce at an average 30-day sales rate per well of 8.5 MMcfe/d,
consisting of 3.7 MMcf/d of natural gas, 747 bbls/d of NGLs and 48
bbls/d of condensate. The two Frye wells, completed using the
company’s optimized completion design, continue their strong
performance to date. Comparing the two Frye wells to their expected
type curve, both wells are currently outperforming their respective
type curves.
The company finished completing the three-well
Manuel pad, which was drilled to an average lateral length of
approximately 6,750 feet and completed in an average of 41 stages.
The three wells are expected to be placed into sales in early
December 2017.
Warrior North Area
In the Warrior North Area, the company has begun
completing the three-well Jenkins pad. The three wells were drilled
to an average lateral length of approximately 6,500 feet. The wells
are expected to be completed at the end of the fourth quarter of
2017 and placed into sales in January 2018. The three existing
wells on the Jenkins pad, which account for approximately 2.6
MMcfe/d of production, will be shut in during the completion and
initial flow back of the three new Jenkins wells.
In addition, the company began drilling the
seven-well Goebeler pad and is currently drilling the fifth of
seven wells on the pad. The seven wells are expected to be drilled
to an average lateral length of approximately 7,500 feet and placed
into sales in the second quarter of 2018.
The combination of the three-well Jenkins pad and
seven-well Goebeler pad will be the primary driver for the
company’s expected 2018 condensate growth rate of 150% - 175%.
Third Quarter Financial
Results
Commodity revenues, including settlements from
derivatives, for the three and nine months ended September 30, 2017
were $46.6 million and $140.6 million, respectively, which
represents an increase of 29% and 14% over the same periods in
2016. Commodity revenues from natural gas liquids (NGLs) and
condensate, including settlements from derivatives, represented 41%
of total commodity revenues for the three months ended September
30, 2017.
Lease operating expense (LOE) from continuing
operations was $30.6 million, or $1.83 per Mcfe for the third
quarter. For the nine months ended September 30, 2017, LOE was
approximately $88.9 million, or $1.83 per Mcfe. General and
administrative (G&A) expenses from continuing operations were
$4.6 million for the third quarter of 2017, or $0.28 per Mcfe. For
the nine months ended September 30, 2017, G&A expenses from
continuing operations were $13.4 million, or $0.28 per Mcfe. Cash
G&A expenses from continuing operations (a non-GAAP measure)
for the three months ended September 30, 2017 were $4.2 million, or
$0.25 per Mcfe. For the nine months ended September 30, 2017, cash
G&A expenses from continuing operations (a non-GAAP measure)
were $12.5 million, or $0.26 per Mcfe. The company expects
substantial reductions, on a per unit basis, for LOE in the fourth
quarter of 2017.
Net loss attributable to common shareholders for
the three months ended September 30, 2017 was $47.1 million, or
$4.76 per basic share. Net loss attributable to common shareholders
for the nine months ended September 30, 2017 was $55.2 million, or
$5.60 per basic share. Adjusted net loss, a non-GAAP measure, for
the three months ended September 30, 2017 was $9.9 million, or
$1.00 per share. Adjusted net loss for the nine months ended
September 30, 2017 was $24.6 million, or $2.50 per share.
EBITDAX from continuing operations, a non-GAAP
measure, was $11.9 million for the third quarter of 2017 and $39.9
million for the nine months ended September 30, 2017, representing
increases of 163% and 25% over the same periods in 2016,
respectively.
Reconciliations of adjusted net loss to GAAP net
loss, EBITDAX to GAAP net loss and G&A to cash G&A for the
three and nine months ended September 30, 2017, as well as a
discussion of the uses of each measure, are presented in the
appendix of this release.
Production Results and Price
Realizations
Third quarter 2017 production volumes from
continuing operations were 182.0 MMcfe/d, consisting of 112.0
MMcf/d of natural gas, 5.1 Mbbls/d of C3+ NGLs, 6.0 Mbbls/d of
ethane and 0.7 Mbbls/d of condensate. NGLs (including ethane) and
condensate accounted for 38% of net production for the third
quarter of 2017. The company exceeded production guidance through
strong operating efficiencies which allowed for earlier turn inline
dates for the Shields and Mackrell pads in the Moraine East
Area.
Including the effects of cash-settled derivatives,
realized prices for the three months ended September 30, 2017 were
$2.66 per Mcf for natural gas, $23.44 per barrel for C3+ NGLs,
$10.14 per barrel for ethane and $44.47 per barrel for condensate.
Before the effects of hedging, realized prices for the three months
ended September 30, 2017 were $2.52 per Mcf for natural gas, $29.62
per barrel for C3+ NGLs, $10.28 per barrel for ethane and $42.00
per barrel for condensate.
Including the effects of cash-settled derivatives,
realized prices for the nine months ended September 30, 2017 were
$2.83 per Mcf for natural gas, $23.40 per barrel for C3+ NGLs,
$9.95 per barrel for ethane and $45.02 per barrel for condensate.
Before the effects of hedging, realized prices for the nine months
ended September 30, 2017 were $2.87 per Mcf for natural gas, $27.82
per barrel for C3+ NGLs, $9.93 per barrel for ethane and $43.58 per
barrel for condensate.
Third Quarter 2017 Capital
Investments
For the third quarter of 2017, net operational
capital investments were approximately $25.1 million. The company
expects to be reimbursed by joint development partners for
approximately $5.9 million of previously incurred costs that were
not billed until the fourth quarter of 2017. Capital investments in
the third quarter of 2017 funded the drilling of seven gross (seven
net) wells, fracture stimulation of six gross (3.4 net) wells and
other projects related to drilling and completing wells in the
Appalachian Basin. Net operated capital expenditures for the
full-year 2017 are still expected to be within the range of the
company’s previously issued guidance of $115.0 million - $130.0
million.
Liquidity Update
As of September 30, 2017, the company had
approximately $3.2 million of cash on hand and outstanding
borrowings under its term loan credit agreement of approximately
$155.5 million with an additional $32.2 of undrawn letters of
credit outstanding. As of September 30, 2017, the company had
approximately $112.3 million of undrawn availability under its term
loan credit agreement.
Fourth Quarter and Full Year 2017
Guidance
Rex Energy is providing guidance for the fourth
quarter of 2017 and maintaining its full-year 2017 guidance ($ in
millions). The company’s fourth quarter 2017 production guidance
accounts for the approximately 2.6 MMcfe/d of production shut-in
due to the completion and initial flowback of the three-well
Jenkins pad in Warrior North. In addition, the company is
maintaining its year-end 2017 exit rate production growth rate
guidance of 15% - 20% upon the commissioning of its fourth
compressor in the Moraine East Area.
|
4Q2017 |
Full Year 2017 |
Production |
195.0 – 205.0 MMcfe/d |
180.0 – 190.0 MMcfe/d |
LOE ($/Mcfe) |
$1.65 - $1.75 |
$1.70 - $1.80 |
Cash G&A ($/Mcfe) |
$0.21 - $0.26 |
$0.20 - $0.25 |
Operational CapitalExpenditures(1) |
-- |
$115.0 - $130.0 MM |
(1) Land acquisition expense and capitalized interest are not
included in the operational capital expenditures budget |
Conference Call Information
Management will host a live conference call and
webcast on Wednesday, November 15, 2017 at 10:00 a.m. Eastern to
review third quarter 2017 financial results and operational
highlights. The telephone number to access the conference call is
(866) 437-1772.
About Rex Energy Corporation
Headquartered in State College, Pennsylvania, Rex
Energy is an independent oil and gas exploration and production
company with its core operations in the Appalachian Basin. The
company’s strategy is to pursue its higher potential exploration
drilling prospects while acquiring oil and natural gas properties
complementary to its portfolio.
Forward-Looking Statements
Except for historical information, all statements
made in this release, including those relating to the timing and
nature of development plans; drilling and completion schedules;
anticipated fracture stimulation activities; expected dates for
placement of wells into sales; and our financial guidance for
fourth quarter and full year 2017 are 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. Forward-looking statements may contain words such as
"expected", "expects", "scheduled", "planned", "plans",
"anticipates" or similar words, and are based on management's
experience and perception of historical trends, current conditions,
and anticipated future developments, as well as other factors
believed to be appropriate. We believe these statements and the
assumptions and estimates contained in this release are reasonable
based on information that is currently available to us. However,
management's assumptions and the company's future performance are
subject to a wide range of business risks and uncertainties, both
known and unknown, and we cannot assure that the company can or
will meet the goals, expectations, and projections included in this
release. Any number of factors could cause our actual results to be
materially different from those expressed or implied in our forward
looking statements, including (without limitation):
- economic conditions in the United States and globally;
- domestic and global supply and demand for oil, NGLs, and
natural gas;
- realized prices for oil, natural gas and NGLs and volatility of
those prices;
- the adequacy and availability of capital resources, credit and
liquidity, including, but not limited to, access to additional
borrowing capacity and our inability to generate sufficient cash
flow from operations to fund our capital expenditures and meet
working capital needs;
- our ability to comply with restrictions imposed by our term
loan credit agreement, secured and unsecured indentures, and other
existing and future financing arrangements;
- our ability to service our outstanding indebtedness;
- impairments of our natural gas, NGL and condensate asset values
due to declines in commodity prices;
- conditions in the domestic and global capital and credit
markets and their effect on us;
- new or changing government regulations, including those
relating to environmental matters, permitting or other aspects of
our operations;
- the willingness and ability of the Organization of Petroleum
Exporting Countries to set and maintain oil price and production
controls;
- the geologic quality of our properties with regard to, among
other things, the existence of hydrocarbons in economic
quantities;
- uncertainties inherent in the estimates of our natural gas, NGL
and condensate reserves;
- our ability to increase natural gas, NGL and condensate
production and income through exploration and development;
- drilling and operating risks;
- counterparty credit risks;
- the success of our drilling techniques in both conventional and
unconventional reservoirs;
- the success of the secondary and tertiary recovery methods we
utilize or plan to employ in the future;
- the number of potential well locations to be drilled, the cost
to drill, and the time frame within which they will be
drilled;
- the ability of contractors to timely and adequately perform
their drilling, construction, well stimulation, completion and
production services;
- the availability of equipment, such as drilling rigs, and
infrastructure, such as transportation, pipelines, processing and
midstream services;
- the effects of adverse weather or other natural disasters on
our operations;
- competition in the oil and gas industry in general, and
specifically in our areas of operations;
- changes in our drilling plans and related budgets;
- the success of prospect development and property
acquisitions;
- the success of our business and financial strategies, and
hedging strategies;
- uncertainties related to the legal and regulatory environment
for our industry and our own legal proceedings and their outcome;
and
- our ability to maintain the listing of our securities on the
NASDAQ Capital Market or any other exchange on which our securities
trade
We undertake no obligation to publicly update or
revise any forward-looking statements. Further information on the
company's risks and uncertainties is available in our filings with
the Securities and Exchange Commission and we strongly encourage
investors to review those filings.
For more information contact:
Investor Relations(814)
278-7130InvestorRelations@rexenergycorp.com
REX ENERGY CORPORATION |
CONSOLIDATED BALANCE SHEETS |
($ in Thousands, Except Share and Per Share
Data) |
|
ASSETS |
September 30,
2017(Unaudited) |
|
December 31, 2016 |
Current Assets |
|
|
|
Cash and
Cash Equivalents |
$ |
3,234 |
|
|
$ |
3,697 |
|
Accounts
Receivable |
25,167 |
|
|
25,448 |
|
Taxes
Receivable |
48 |
|
|
211 |
|
Short-Term Derivative Instruments |
3,904 |
|
|
1,873 |
|
Inventory, Prepaid Expenses and Other |
3,524 |
|
|
2,546 |
|
Total Current Assets |
35,877 |
|
|
33,775 |
|
Property and Equipment (Successful Efforts
Method) |
|
|
|
Evaluated
Oil and Gas Properties |
1,022,857 |
|
|
1,053,461 |
|
Unevaluated Oil and Gas Properties |
201,331 |
|
|
215,794 |
|
Other
Property and Equipment |
22,100 |
|
|
21,401 |
|
Wells and
Facilities in Progress |
46,814 |
|
|
21,964 |
|
Pipelines |
16,803 |
|
|
18,029 |
|
Total Property and Equipment |
1,309,905 |
|
|
1,330,649 |
|
Less:
Accumulated Depreciation , Depletion and Amortization |
(452,882 |
) |
|
(475,205 |
) |
Net Property and Equipment |
857,023 |
|
|
855,444 |
|
Other
Assets |
2,475 |
|
|
2,492 |
|
Long-Term
Derivative Instruments |
1,465 |
|
|
2,212 |
|
Total Assets |
$ |
896,840 |
|
|
$ |
893,923 |
|
LIABILITIES AND EQUITY |
|
|
|
Current Liabilities |
|
|
|
Accounts
Payable |
$ |
48,221 |
|
|
$ |
40,712 |
|
Current
Maturities of Long-Term Debt |
1,859 |
|
|
764 |
|
Accrued
Liabilities |
35,733 |
|
|
37,207 |
|
Short-Term Derivative Instruments |
12,477 |
|
|
25,025 |
|
Total Current Liabilities |
98,290 |
|
|
103,708 |
|
Long-Term
Derivative Instruments |
13,486 |
|
|
7,227 |
|
Senior
Secured Line of Credit and Long-Term Debt, Net of Issuance
Costs |
-- |
|
|
113,785 |
|
Term
Loans, Net |
148,351 |
|
|
-- |
|
Senior
Notes, Net |
654,713 |
|
|
638,161 |
|
Other
Long-Term Debt |
8,615 |
|
|
3,409 |
|
Other
Deposits and Liabilities |
7,396 |
|
|
8,671 |
|
Future
Abandonment Cost |
9,027 |
|
|
8,736 |
|
Total Liabilities |
$ |
939,878 |
|
|
$ |
883,697 |
|
|
|
|
|
Stockholder Equity |
|
|
|
Preferred
Stock, $.001 par value per share, 100,000 shares authorized and
3,987 issuedand outstanding on September 30, 2017 and December 31,
2016 |
$ |
1 |
|
|
$ |
1 |
|
Common
Stock, $.001 par value per share, 100,000,000 shares authorized
and9,935,383 shares issued and outstanding on September 30, 2017
and 9,787,146 sharesissued and outstanding on December 31,
2016 |
10 |
|
|
10 |
|
Additional Paid-In Capital |
652,055 |
|
|
650,669 |
|
Accumulated Deficit |
(695,104 |
) |
|
(640,454 |
) |
Total Stockholders’ Equity |
(43,038 |
) |
|
10,226 |
|
Total Liabilities and Owners’ Equity |
$ |
896,840 |
|
|
$ |
893,923 |
|
|
|
REX ENERGY CORPORATION |
CONSOLIDATED STATEMENTS OF
OPERATIONS |
(Unaudited, in Thousands, Except per Share
Data) |
|
|
For the Three Months EndedSeptember
30, |
|
For the Nine Months
EndedSeptember 30, |
|
2017 |
|
|
2016 |
|
|
2017 |
|
|
2016 |
|
OPERATING REVENUE |
|
|
|
|
|
|
|
Natural Gas, NGL and Condensate Sales |
$ |
47,970 |
|
|
$ |
34,034 |
|
|
$ |
147,491 |
|
|
$ |
90,978 |
|
Other Operating Revenue |
5 |
|
|
5 |
|
|
16 |
|
|
12 |
|
TOTAL OPERATING REVENUE |
47,975 |
|
|
34,039 |
|
|
147,507 |
|
|
90,990 |
|
OPERATING EXPENSES |
|
|
|
|
|
|
|
Production and Lease Operating Expense |
30,574 |
|
|
26,333 |
|
|
88,882 |
|
|
76,005 |
|
General and Administrative Expense |
4,617 |
|
|
5,116 |
|
|
13,444 |
|
|
15,237 |
|
Gain (Loss) on Disposal of Assets |
252 |
|
|
10 |
|
|
(1,707 |
) |
|
(4,285 |
) |
Impairment Expense |
11,877 |
|
|
9,563 |
|
|
16,455 |
|
|
45,344 |
|
Exploration Expense |
94 |
|
|
216 |
|
|
413 |
|
|
1,954 |
|
Depreciation, Depletion, Amortization and Accretion |
14,617 |
|
|
15,109 |
|
|
45,586 |
|
|
46,371 |
|
Other Operating Expense |
449 |
|
|
9,899 |
|
|
331 |
|
|
10,930 |
|
TOTAL OPERATING EXPENSES |
62,480 |
|
|
66,246 |
|
|
163,404 |
|
|
191,556 |
|
LOSS FROM OPERATIONS |
(14,505 |
) |
|
(32,207 |
) |
|
(15,897 |
) |
|
(100,566 |
) |
OTHER EXPENSE (EXPENSE) |
|
|
|
|
|
|
|
Interest Expense |
(13,754 |
) |
|
(9,646 |
) |
|
(35,019 |
) |
|
(34,115 |
) |
Loss on Derivatives, Net |
(18,083 |
) |
|
16,866 |
|
|
684 |
|
|
(8,254 |
) |
Other (Expense) Income |
(185 |
) |
|
16 |
|
|
(193 |
) |
|
28 |
|
Debt Exchange Expense |
-- |
|
|
(35 |
) |
|
-- |
|
|
(9,048 |
) |
(Loss) Gain on Extinguishment of Debt |
(7 |
) |
|
423 |
|
|
(3,029 |
) |
|
24,130 |
|
TOTAL OTHER INCOME (EXPENSE) |
(32,029 |
) |
|
7,624 |
|
|
(37,557 |
) |
|
(27,259 |
) |
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME
TAX |
(46,534 |
) |
|
(24,583 |
) |
|
(53,454 |
) |
|
(127,825 |
) |
Income Tax Benefit |
-- |
|
|
8,106 |
|
|
-- |
|
|
5,785 |
|
NET LOSS FROM CONTINUING OPERATIONS |
(46,534 |
) |
|
(16,477 |
) |
|
(53,454 |
) |
|
(122,040 |
) |
Income
From Discontinued Operations, Net of Income Taxes |
-- |
|
|
21,892 |
|
|
-- |
|
|
12,719 |
|
NET INCOME (LOSS) |
(46,534 |
) |
|
5,415 |
|
|
(53,454 |
) |
|
(109,321 |
) |
Preferred Stock Dividends |
(598 |
) |
|
(613 |
) |
|
(1,794 |
) |
|
(4,441 |
) |
Effect
of Preferred Stock Conversion |
-- |
|
|
-- |
|
|
-- |
|
|
72,316 |
|
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON
SHAREHOLDERS |
$ |
(47,132 |
) |
|
$ |
4,802 |
|
|
$ |
(55,248 |
) |
|
$ |
(41,446 |
) |
Earnings
per common share: |
|
|
|
|
|
|
|
Basic –
Net Loss From Continuing Operations Attributable to Rex Energy
Common Shareholders |
$ |
(4.76 |
) |
|
$ |
(1.89 |
) |
|
$ |
(5.60 |
) |
|
$ |
(7.41 |
) |
Basic –
Net Income From Discontinued Operations Attributable to Rex Energy
Common Shareholders |
-- |
|
|
2.41 |
|
|
-- |
|
|
1.74 |
|
Basic –
Net Income (Loss) Attributable to Rex Energy Common
Shareholders |
$ |
(4.76 |
) |
|
$ |
0.52 |
|
|
$ |
(5.60 |
) |
|
$ |
(5.67 |
) |
Basic –
Weighted Average Shares of Common Stock Outstanding |
9,906 |
|
|
9,080 |
|
|
9,859 |
|
|
7,310 |
|
Diluted
– Net Loss From Continuing Operations Attributable to Rex Energy
Common Shareholders |
$ |
(4.76 |
) |
|
$ |
(1.89 |
) |
|
$ |
(5.60 |
) |
|
$ |
(7.41 |
) |
Diluted
– Net Income From Discontinued Operations Attributable to Rex
Energy Common Shareholders |
-- |
|
|
2.41 |
|
|
-- |
|
|
1.74 |
|
Diluted
– Net Income (Loss) Attributable to Rex Energy Common
Shareholders |
$ |
(4.76 |
) |
|
$ |
0.52 |
|
|
$ |
(5.60 |
) |
|
$ |
(5.67 |
) |
Diluted
– Weighted Average Shares of Common Stock Outstanding |
9,906 |
|
|
9,080 |
|
|
9,859 |
|
|
7,310 |
|
REX ENERGY CORPORATION |
CONSOLIDATED OPERATIONAL
HIGHLIGHTS |
|
|
|
Three Months Ending |
|
Nine Months Ending |
|
|
September 30, |
|
September 30, |
|
|
2017 |
|
|
2016 |
|
2017 |
|
|
2016 |
Oil,
Natural Gas, NGL and Ethane sales (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales |
|
$ |
25,997 |
|
|
$ |
16,871 |
|
$ |
86,438 |
|
|
$ |
48,431 |
Condensate sales |
|
|
2,574 |
|
|
|
4,096 |
|
|
8,987 |
|
|
|
8,998 |
Natural gas liquids (C3+) sales |
|
|
13,770 |
|
|
|
8,211 |
|
|
36,896 |
|
|
|
22,053 |
Ethane sales |
|
|
5,630 |
|
|
|
4,855 |
|
|
15,170 |
|
|
|
11,495 |
Cash-settled derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas |
|
|
1,432 |
|
|
|
1,200 |
|
|
(1,333 |
) |
|
|
24,280 |
Condensate |
|
|
151 |
|
|
|
93 |
|
|
297 |
|
|
|
2,191 |
Natural gas liquids (C3+) |
|
|
(2,871 |
) |
|
|
830 |
|
|
(5,872 |
) |
|
|
6,040 |
Ethane |
|
|
(77 |
) |
|
|
97 |
|
|
19 |
|
|
|
241 |
Total
oil, gas, NGL and Ethane sales including cash settled
derivatives |
|
$ |
46,606 |
|
|
$ |
36,253 |
|
$ |
140,602 |
|
|
$ |
123,729 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Production during the period: |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Mcf) |
|
|
10,299,872 |
|
|
|
10,927,477 |
|
|
30,101,503 |
|
|
|
33,559,096 |
Condensate (Bbls) |
|
|
61,280 |
|
|
|
105,517 |
|
|
206,206 |
|
|
|
259,145 |
Natural gas liquids (C3+) (Bbls) |
|
|
464,929 |
|
|
|
498,217 |
|
|
1,326,076 |
|
|
|
1,495,961 |
Ethane (Bbls) |
|
|
547,538 |
|
|
|
607,340 |
|
|
1,527,117 |
|
|
|
1,578,480 |
Total (Mcfe)1 |
|
|
16,742,354 |
|
|
|
18,193,921 |
|
|
48,457,897 |
|
|
|
53,560,612 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Production – average per day: |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Mcf) |
|
|
111,955 |
|
|
|
118,777 |
|
|
110,262 |
|
|
|
122,478 |
Condensate (Bbls) |
|
|
666 |
|
|
|
1,147 |
|
|
755 |
|
|
|
946 |
Natural gas liquids (C3+) (Bbls) |
|
|
5,054 |
|
|
|
5,415 |
|
|
4,857 |
|
|
|
5,460 |
Ethane (Bbls) |
|
|
5,952 |
|
|
|
6,602 |
|
|
5,594 |
|
|
|
5,761 |
Total (Mcfe)1 |
|
|
181,982 |
|
|
|
197,760 |
|
|
177,501 |
|
|
|
195,480 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
price per unit: |
|
|
|
|
|
|
|
|
|
|
|
|
Realized
natural gas price per Mcf – as reported |
|
$ |
2.52 |
|
|
$ |
1.54 |
|
$ |
2.87 |
|
|
$ |
1.44 |
Realized
impact from cash settled derivatives per Mcf |
|
|
0.14 |
|
|
|
0.11 |
|
|
(0.04 |
) |
|
|
0.73 |
Net
realized price per Mcf |
|
$ |
2.66 |
|
|
$ |
1.65 |
|
$ |
2.83 |
|
|
$ |
2.17 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized
condensate price per Bbl – as reported |
|
$ |
42.00 |
|
|
$ |
38.82 |
|
$ |
43.58 |
|
|
$ |
34.72 |
Realized
impact from cash settled derivatives per Bbl2 |
|
|
2.47 |
|
|
|
0.88 |
|
|
1.44 |
|
|
|
8.46 |
Net
realized price per Bbl |
|
$ |
44.47 |
|
|
$ |
39.70 |
|
$ |
45.02 |
|
|
$ |
43.18 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized
natural gas liquids (C3+) price per Bbl – as reported |
|
$ |
29.62 |
|
|
$ |
16.48 |
|
$ |
27.82 |
|
|
$ |
14.74 |
Realized
impact from cash settled derivatives per Bbl |
|
|
(6.18 |
) |
|
|
1.67 |
|
|
(4.42 |
) |
|
|
4.04 |
Net
realized price per Bbl |
|
$ |
23.44 |
|
|
$ |
18.15 |
|
$ |
23.40 |
|
|
$ |
18.78 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized
ethane price per Bbl – as reported |
|
$ |
10.28 |
|
|
$ |
7.99 |
|
$ |
9.93 |
|
|
$ |
7.28 |
Realized
impact from cash settled derivatives per Bbl |
|
|
(0.14 |
) |
|
|
0.16 |
|
|
0.02 |
|
|
|
0.16 |
Net
realized price per Bbl |
|
$ |
10.14 |
|
|
$ |
8.15 |
|
$ |
9.95 |
|
|
$ |
7.44 |
|
|
|
|
|
|
|
|
|
|
|
|
|
LOE/Mcfe |
|
$ |
1.83 |
|
|
$ |
1.45 |
|
$ |
1.83 |
|
|
$ |
1.42 |
Cash
G&A/Mcfe |
|
$ |
0.25 |
|
|
$ |
0.23 |
|
$ |
0.26 |
|
|
$ |
0.25 |
1 Oil and natural gas liquids are converted at the rate of one
barrel of oil equivalent to six Mcfe. |
2 Includes the effect of derivatives not classified as
discontinued operations. When including the effect of Illinois
Basin production, derivativesincreased prices by $0.87/bbl and
$3.85/bbl for the three and nine month periods ended September 30,
2016, respectively |
|
|
REX ENERGY CORPORATION |
COMMODITY DERIVATIVES – HEDGE POSITION AS OF
11/10/2017 |
|
|
2017 |
|
2018 |
|
Oil Derivatives (Bbls) |
|
|
|
|
Swap Contracts |
|
|
|
|
Volume |
|
10,000 |
|
|
95,000 |
|
Price |
$ |
54.00 |
|
$ |
53.93 |
|
Collar Contracts |
|
|
|
|
Volume |
|
-- |
|
|
18,000 |
|
Ceiling |
$ |
-- |
|
$ |
60.00 |
|
Floor |
$ |
-- |
|
$ |
53.00 |
|
Collar Contracts with Short Puts |
|
|
|
|
Volume |
|
26,000 |
|
|
66,000 |
|
Ceiling |
$ |
61.35 |
|
$ |
61.55 |
|
Floor |
$ |
49.23 |
|
$ |
51.59 |
|
Short Put |
$ |
39.62 |
|
$ |
42.50 |
|
Natural Gas Derivatives (Mcf) |
|
|
|
|
Swap Contracts |
|
|
|
|
Volume |
|
1,980,000 |
|
|
15,335,000 |
|
Price |
$ |
3.31 |
|
$ |
3.10 |
|
Swaption Contracts |
|
|
|
|
Volume |
|
400,000 |
|
|
-- |
|
Price |
$ |
3.33 |
|
$ |
-- |
|
Put Spreads |
|
|
|
|
Volume |
|
-- |
|
|
-- |
|
Floor |
$ |
-- |
|
$ |
-- |
|
Short Put |
$ |
-- |
|
$ |
-- |
|
Collar Contracts |
|
|
|
|
Volume |
|
300,000 |
|
|
450,000 |
|
Ceiling |
$ |
3.65 |
|
$ |
3.65 |
|
Floor |
$ |
2.54 |
|
$ |
3.20 |
|
Collar Contracts with Short Puts |
|
|
|
|
Volume |
|
3,230,000 |
|
|
10,600,000 |
|
Ceiling |
$ |
3.85 |
|
$ |
3.52 |
|
Floor |
$ |
2.98 |
|
$ |
2.90 |
|
Short Put |
$ |
2.30 |
|
$ |
2.33 |
|
Call Contracts |
|
|
|
|
Volume |
|
1,399,140 |
|
|
16,489,900 |
|
Ceiling |
$ |
4.51 |
|
$ |
4.64 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Liquids
(Bbls) |
|
|
|
|
Swap Contracts |
|
|
|
|
Propane (C3) |
|
|
|
|
Volume |
|
162,000 |
|
|
715,500 |
|
Price |
$ |
23.30 |
|
$ |
26.72 |
|
Butane (C4) |
|
|
|
|
Volume |
|
40,000 |
|
|
220,000 |
|
Price |
$ |
28.54 |
|
$ |
33.66 |
|
Isobutane (IC4) |
|
|
|
|
Volume |
|
20,000 |
|
|
102,000 |
|
Price |
$ |
29.19 |
|
$ |
33.61 |
|
Natural Gasoline (C5+) |
|
|
|
|
Volume |
|
44,000 |
|
|
231,072 |
|
Price |
$ |
49.33 |
|
$ |
49.74 |
|
Ethane |
|
|
|
|
Volume |
|
150,000 |
|
|
1,150,000 |
|
Price |
$ |
10.58 |
|
$ |
12.95 |
|
Natural Gas Basis (Mcf) |
|
|
|
|
Swap Contracts |
|
|
|
|
Dominion Appalachia |
|
|
|
|
Volume |
|
2,440,000 |
|
|
18,980,000 |
|
Price |
$ |
(0.79 |
) |
$ |
(0.81 |
) |
Texas Gas Zone 1 |
|
|
|
|
Volume |
|
6,120,000 |
|
|
14,600,000 |
|
Price |
$ |
(0.13 |
) |
$ |
(0.13 |
) |
NYMEX Heating Oil (Gal) |
|
|
|
|
Swap Contracts |
|
|
|
|
Volume |
|
-- |
|
|
-- |
|
Price |
$ |
-- |
|
$ |
-- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
APPENDIX REX
ENERGY CORPORATIONNON-GAAP MEASURES
EBITDAX
“EBITDAX” means, for any period, the sum of net
income for such period plus the following expenses, charges or
income to the extent deducted from or added to net income in such
period: interest, income taxes, DD&A, unrealized losses from
financial derivatives, non-recurring gains and losses, exploration
expenses and other similar non-cash charges, minus all non-cash
income, including but not limited to, income from unrealized
financial derivatives and gains on asset dispositions, added to net
income. EBITDAX, as defined above, is used as a financial
measure by our management team and by other users of its financial
statements, such as our commercial bank lenders to analyze such
things as:
- Our operating performance and return on capital in comparison
to those of other companies in our industry, without regard to
financial or capital structure;
- The financial performance of our assets and valuation of the
entity without regard to financing methods, capital structure or
historical cost basis;
- Our ability to generate cash sufficient to pay interest costs,
support our indebtedness and make cash distributions to our
stockholders; and
- The viability of acquisitions and capital expenditure projects
and the overall rates of return on alternative investment
opportunities.
EBITDAX is not a calculation based on GAAP
financial measures and should not be considered as an alternative
to net income (loss) (the most directly comparable GAAP financial
measure) in measuring our performance, nor should it be used as an
exclusive measure of cash flows, because it does not consider the
impact of working capital growth, capital expenditures, debt
principal reductions, and other sources and uses of cash, which are
disclosed in our consolidated statements of cash flows.
We have reported EBITDAX because it is a financial
measure used by our existing commercial lenders, and because this
measure is commonly reported and widely used by investors as an
indicator of a company’s operating performance and ability to incur
and service debt. You should carefully consider the specific
items included in our computations of EBITDAX. While we have
disclosed EBITDAX to permit a more complete comparative analysis of
our operating performance and debt servicing ability relative to
other companies, you are cautioned that EBITDAX as reported by us
may not be comparable in all instances to EBITDAX as reported by
other companies. EBITDAX amounts may not be fully available
for management’s discretionary use, due to requirements to conserve
funds for capital expenditures, debt service and other
commitments.
We believe that EBITDAX assists our lenders and
investors in comparing our performance on a consistent basis
without regard to certain expenses, which can vary significantly
depending upon accounting methods. Because we may borrow money
to finance our operations, interest expense is a necessary element
of our costs. In addition, because we use capital assets,
DD&A are also necessary elements of our costs. Finally, we
are required to pay federal and state taxes, which are necessary
elements of our costs. Therefore, any measures that exclude
these elements have material limitations.
To compensate for these limitations, we believe it
is important to consider both net income determined under GAAP and
EBITDAX to evaluate our performance.
For purposes of consistency with current
calculations, we have revised certain amounts relating to prior
period EBITDAX. The following table presents a reconciliation of
our net income to EBITDAX for each of the periods presented.
|
|
Three Months EndedSeptember 30, |
|
Nine Months EndedSeptember
30, |
|
|
2017 |
|
|
2016 |
|
|
2017 |
|
|
2016 |
|
Net Loss
From Continuing Operations |
|
$ |
(46,534 |
) |
|
$ |
(16,477 |
) |
|
$ |
(53,454 |
) |
|
$ |
(122,040 |
) |
Add Back Non-Recurring Costs (Income)1 |
|
765 |
|
|
8,306 |
|
|
4,224 |
|
|
(6,388 |
) |
Add Back Depletion, Depreciation, Amortization and Accretion |
|
14,617 |
|
|
15,109 |
|
|
45,586 |
|
|
46,371 |
|
Add Back Non-Cash Compensation Expense |
|
395 |
|
|
990 |
|
|
966 |
|
|
2,006 |
|
Add Back Interest Expense |
|
13,754 |
|
|
9,646 |
|
|
35,019 |
|
|
34,115 |
|
Add Back Impairment Expense |
|
11,877 |
|
|
9,563 |
|
|
16,455 |
|
|
45,344 |
|
Add Back Exploration Expenses |
|
94 |
|
|
216 |
|
|
413 |
|
|
1,954 |
|
Add Back (Less) Loss (Gain) on Disposal of Assets |
|
252 |
|
|
10 |
|
|
(1,707 |
) |
|
(4,285 |
) |
Add Back (Less) Loss (Gain) on Financial Derivatives |
|
18,083 |
|
|
(16,866 |
) |
|
(684 |
) |
|
8,254 |
|
Add Back (Less) Cash Settlement of Derivatives |
|
(1,365 |
) |
|
2,145 |
|
|
(6,889 |
) |
|
32,485 |
|
Less Income Tax Benefit |
|
-- |
|
|
(8,106 |
) |
|
-- |
|
|
(5,785 |
) |
EBITDAX
From Continuing Operations |
|
$ |
11,938 |
|
|
$ |
4,536 |
|
$ |
39,929 |
|
$ |
32,031 |
|
Net
Income From Discontinued Operations |
|
$ |
-- |
|
|
$ |
21,892 |
|
$ |
-- |
|
$ |
12,719 |
|
Add Back Depletion, Depreciation, Amortization and Accretion |
|
-- |
|
|
18 |
|
|
-- |
|
|
5,100 |
|
Add Back Non-Cash Compensation Expense |
|
-- |
|
|
(366 |
) |
|
-- |
|
|
(107 |
) |
Add Back Interest Expense |
|
-- |
|
|
1 |
|
|
-- |
|
|
4 |
|
Add Back Impairment Expense |
|
-- |
|
|
-- |
|
|
-- |
|
|
3,543 |
|
Add Back Exploration Expense |
|
-- |
|
|
-- |
|
|
-- |
|
|
143 |
|
Less Gain on Disposal of Assets |
|
-- |
|
|
(30,491 |
) |
|
-- |
|
|
(30,535 |
) |
Add Back Income Tax Expense |
|
-- |
|
|
8,354 |
|
|
-- |
|
|
7,852 |
|
Add EBITDAX From Discontinued Operations |
|
$ |
-- |
|
|
$ |
(592 |
) |
|
$ |
-- |
|
|
$ |
(1,281 |
) |
EBITDAX
(Non-GAAP) |
|
$ |
11,938 |
|
|
$ |
3,944 |
|
|
$ |
39,929 |
|
|
$ |
30,750 |
|
|
1 For the three months ended September 30, 2017,
includes a net $0.2 million of advisory services related to an
engineering study and $0.5 million in non-recurring legal and
insurance costs. For the nine months ended September 30, 2017,
includes a net $0.6 million of advisory services related to our
joint venture drilling programs and an engineering study, $0.5
million in non-recurring legal and insurance costs and $3.0 million
in loss on the extinguishment of debt. For the three months ended
September 30, 2016, includes approximately $8.3 million in expense
related to a firm transportation contract. For the nine
months ended September 30, 2016, includes approximately $24.1
million in gain on extinguishment of debt, net of $8.3 million in
expense related to firm transportation contract and $9.0 million in
debt exchange expenses. |
|
|
Adjusted Net Loss
“Adjusted Net Loss” means, for any period, the sum of net income
(loss) from continuing operations before income taxes for the
period plus the following expenses, charges or income, in each
case, to the extent deducted from or added to net income in the
period: unrealized losses from financial derivatives, non-cash
compensation expense, dry hole expenses, disposals of assets,
impairment and other one-time or non-recurring charges, minus all
gains from unrealized financial derivatives, disposal of assets and
deferred income tax benefits, added to net income. Adjusted Net
Loss is used as a financial measure by Rex Energy's management team
and by other users of its financial statements, to analyze its
financial performance without regard to non-cash deferred taxes and
non-cash unrealized losses or gains from oil and gas derivatives.
Adjusted Net Loss is not a calculation based on GAAP financial
measures and should not be considered as an alternative to net
income (loss) in measuring the company's performance.
Rex Energy reports Adjusted Net Loss because it believes that
this measure is commonly reported and widely used by investors as
an indicator of a company's operating performance. You should
carefully consider the specific items included in the company's
computation of this measure. You are cautioned that Adjusted Net
Income as reported by Rex Energy may not be comparable in all
instances to that reported by other companies.
To compensate for these limitations, the company believes it is
important to consider both net income determined under GAAP and
Adjusted Net Income.
The following table presents a reconciliation of Rex Energy’s
net income from continuing operations to its adjusted net loss for
each of the periods presented ($ in thousands):
|
For the Three Months Ended |
|
For the Nine Months Ended |
|
September 30, |
|
September 30, |
|
|
2017 |
|
|
2016 |
|
|
|
2017 |
|
|
2016 |
|
Loss
From Continuing Operations Before Income Taxes, as reported |
$ |
(46,534 |
) |
$ |
(24,583 |
) |
|
$ |
(53,454 |
) |
$ |
(127,825 |
) |
(Gain) Loss on Derivatives, Net |
|
18,083 |
|
|
(16,866 |
) |
|
|
(684 |
) |
|
8,254 |
|
Cash Settlement of Derivatives |
|
(1,365 |
) |
|
2,145 |
|
|
|
(6,889 |
) |
|
32,485 |
|
Add Back (Gain) Loss from Financial Derivatives |
|
16,718 |
|
|
(14,721 |
) |
|
|
(7,573 |
) |
|
40,739 |
|
Add Back Non-Recurring Costs1 |
|
765 |
|
|
8,306 |
|
|
|
4,224 |
|
|
(6,388 |
) |
Add Back Impairment Expense |
|
11,877 |
|
|
9,563 |
|
|
|
16,455 |
|
|
45,344 |
|
Add Back Dry Hole Expense |
|
-- |
|
|
2 |
|
|
|
13 |
|
|
848 |
|
Add Back Non-Cash Compensation Expense |
|
395 |
|
|
990 |
|
|
|
966 |
|
|
2,006 |
|
Less Gain on Disposal of Assets |
|
252 |
|
|
10 |
|
|
|
(1,707 |
) |
|
(4,285 |
) |
Loss
From Continuing Operations Before Income Taxes, adjusted |
$ |
(16,527 |
) |
$ |
(20,433 |
) |
|
$ |
(41,076 |
) |
$ |
(49,561 |
) |
Less Income Tax Benefit, adjusted2 |
|
6,611 |
|
|
8,173 |
|
|
|
16,430 |
|
|
19,824 |
|
Adjusted
Net Loss From Continuing Operations |
$ |
(9,916 |
) |
$ |
(12,260 |
) |
|
$ |
(24,646 |
) |
$ |
(29,737 |
) |
|
|
|
|
|
|
|
|
|
|
Basic –
Adjusted Net Loss Per Share |
$ |
(1.00 |
) |
$ |
(1.35 |
) |
|
$ |
(2.50 |
) |
$ |
(4.07 |
) |
Basic –
Weighted Average Shares of Common Stock Outstanding |
|
9,906 |
|
|
9,080 |
|
|
|
9,859 |
|
|
7,310 |
|
1 For the three months ended September 30, 2017, includes a
net $0.2 million of advisory services related to an engineering
study and $0.5 million in non-recurring legal and insurance costs.
For the nine months ended September 30, 2017, includes a net $0.6
million of advisory services related to our joint venture drilling
programs and an engineering study, $0.5 million in non-recurring
legal and insurance costs and $3.0 million in loss on the
extinguishment of debt. For the three months ended September 30,
2016, includes approximately $8.3 million in expense related to a
firm transportation contract. For the nine months ended
September 30, 2016, includes approximately $24.1 million in gain on
extinguishment of debt, net of $8.3 million in expense related to
firm transportation contract and $9.0 million in debt exchange
expenses. |
2 Assumes an effective tax rate of 40% |
Cash General and Administrative
Expenses
Cash General and Administrative Expenses (Cash
G&A) is the difference between GAAP G&A and non-Cash
G&A, which is primarily comprised of non-cash compensation
expense. Rex Energy has reported Cash G&A because it believes
that this measure is commonly reported and widely used by
management and investors as an indicator of overhead efficiency
without regard to non-cash expenditures, such as stock
compensation. Cash G&A is not a calculation based on GAAP
financial measures and should not be considered as an alternative
to GAAP G&A in measuring the company’s performance. You should
carefully consider the specific items included in the company’s
computation of this measure. You are cautioned that Cash G&A as
reported by Rex Energy may not be comparable in all instances to
that reported by other companies.
To compensate for these limitations, the company
believes it is important to consider both Cash G&A and GAAP
G&A. The following table presents a reconciliation of Rex
Energy’s GAAP G&A to its Cash G&A for each of the periods
presented (in thousands):
|
Three Months Ended September
30, |
|
Nine Months Ended September
30, |
|
2017 |
|
2016 |
|
2017 |
|
2016 |
GAAP
G&A |
$ |
4,617 |
|
$ |
5,116 |
|
$ |
13,444 |
|
$ |
15,237 |
Non-Cash
Compensation Expense |
395 |
|
990 |
|
966 |
|
2,006 |
Cash
G&A |
$ |
4,222 |
|
$ |
4,126 |
|
$ |
12,478 |
|
$ |
13,231 |