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Energen’s Gen 3 Wells Continue to Deliver Outstanding Results
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3Q17 Production Beats Guidance by 9%; All Commodities Exceed Expectations

4Q17 Production Guidance Raised 5%

Per-Unit LOE and SG&A Decrease Substantially Again in 3Q17

NOTE: 3Q17 conference call slides available at www.energen.com

BIRMINGHAM, Ala.--(BUSINESS WIRE)--Nov. 8, 2017-- Energen Corporation (NYSE: EGN) (“Energen” or the “company”) today announced financial and operating results for the third quarter ended September 30, 2017.

FINANCIAL AND OPERATING HIGHLIGHTS

PRODUCTION

  • 3Q17 production of 81.3 mboepd exceeded guidance by 9% and surpassed 2Q17 production by 12%.
  • 3Q17 oil production grew 9% from 2Q17.
  • Revised CY17 production of 73.2 mboepd is on track to exceed CY16 volumes by 34% (prior estimate was 29%).
  • YOY production growth in Midland and Delaware basins is now estimated to be 43% as company focuses on development of multiple horizontal shale plays.
  • 4Q17 production estimate raised for all commodities; YOY growth in the 4Q exit rate is now estimated to be 60%.

EARNINGS AND EXPENSES

  • 3Q17 adjusted EBITDAX of $174 mm grew 22% from 2Q17 and beat internal expectations by 14%.
  • Per-unit LOE (including marketing and transportation) beat the guidance midpoint by 17%.
  • Per unit SG&A beat the guidance midpoint by 12%.

CAPITAL EXPENDITURES

  • 2017 drilling and development capital range is unchanged at $850 - $900 mm.
  • Energen closed on an additional 1,300 net acres of unproved leasehold in 3Q17, bringing its YTD acquisition of unproved bolt-on acreage to 11,000 net acres for ≈$235 mm, or ≈$21,400/acre.

3Q17 WELL RESULTS

  • 26 gross (25 net) wells in the Midland and Delaware basins were turned to production in 3Q17; 77% are multi-zone pattern wells completed in batches.
  • The cumulative production of 80 Gen 3 wells are performing at or above the highest EUR type curve and significantly outperforming the midpoint EUR type curve; 78% are multi-zone pattern wells completed in batches.
  • Public data continues to show that Energen’s Gen 3 wells in the Midland and Delaware basins are outperforming other operators’ wells.

Comments from the CEO

“Energen’s execution and operational success continued in the third quarter of 2017,” said Energen Chief Executive Officer James McManus. “Once again, we delivered on our drilling and development plans; we exceeded our expectations for oil and total production; and we further reduced our LOE and G&A.

“Our Gen 3 wells continue to perform at or above our highest EUR type curves and at or above wells completed by other operators. Importantly, we expect our Gen 3 multi-zone pattern wells to continue driving production growth as we move forward. We have increased our guidance for 4th quarter production in all commodities, with estimated total production up 5 percent; and we now expect year-over-year production growth in 2017 to be 34 percent.

“During the 3rd quarter, we continued to execute on our bolt-on acquisition program, which we believe has created significant value for Energen. Over the last 21 months, we have added approximately 20,300 net acres in prime Delaware and Midland basin locations for an average price of about $17,500 an acre,” McManus said.

“We are extremely pleased with our performance this quarter and very excited about our future prospects as we successfully implement our 2017 drilling and development program and plan for 2018. We are confident that Energen is well-positioned to continue delivering strong results and creating shareholder value now and in the future.”

Operations Update

In the third quarter of 2017, Energen turned to production 17 gross (16 net) wells in the Midland Basin and 9 gross (9 net) wells in the Delaware Basin; 77 percent are multi-zone pattern wells completed in batches. The company is currently operating six horizontal drilling rigs and two frac crews.

2017 First Production/Flow back (Operated Horizontal Wells – Gross/Net)

    1Q17a   2Q17a   3Q17a   4Q17e   CY17e
Midland Basin   10/9   27/27   17/16   20/16   74/68
Delaware Basin   2/2   18/18   9/9   5/5   34/34
         

3Q17 Wells Turned to Production

Area   # of Wells  

Average
Completed
Lateral Length

 

Avg. Peak 24-
Hour IP

 

Avg. Peak
30-day IP

      Boepd   %Oil   Boepd   %Oil
Delaware Basin   7  

Wolfcamp A (6)
Wolfcamp B (1)

  8,851’   2,806   55   2,204   51
Northern Midland Basin††   7  

Wolfcamp A (3)
Wolfcamp B (4)

  9,189’   1,466   81   1,070   83

Excludes 2 Wolfcamp BC wells
†† Excludes 10 Northern Midland Basin Spraberry interval wells due to timing of first production or disposal-related choke management

For 80 Gen 3 wells drilled to date (78 percent of which were multi-zone pattern wells completed in batches), the average cumulative production uplift of wells in each formation group (normalized to 10,000’) is performing at or above the highest EUR type curve – and significantly outperforming the midpoint EUR type curve – identified for wells in that group completed with pre-Gen 3 frac designs. These are key measures of success for Energen’s latest frac design.

Relative to the midpoint EUR type curve, the average cumulative production uplift of the Gen 3 wells normalized to 10,000’ is:

  • ≈21% over a 1.75 MMBOE type curve at 340 days for 27 Delaware Basin Wolfcamp A and B wells – 56% are multi-zone pattern wells completed in batches
  • ≈40% over a 1.2 MMBOE type curve at 175 days for 18 wells in the Spraberry package – 89% are multi-zone pattern wells completed in batches
  • ≈6% over a 1.2 MMBOE type curve at 250 days for 17 northern Midland Basin Wolfcamp A and B wells – 76% are multi-zone pattern wells completed in batches
  • ≈11% over a 1.2 MMBOE type curve at 250 days for 16 central Midland Basin Wolfcamp A and B wells – 100% are multi-zone pattern wells in batches
  • ≈45% over an 850 MBOE type curve at 240 days for 2 central Midland Basin Lower Spraberry wells – 100% are multi-zone pattern wells completed in batches

In another assessment of success, the average cumulative production of Energen’s Midland Basin Gen 3 multi-zone pattern wells completed in batches continues to outperform other operators’ pattern wells, and the average cumulative production of Energen’s Gen 3 wells (pattern and stand-alone) in the Midland and Delaware basins is outperforming other operators’ wells with proppant loads of 1,700-2,500 pounds per foot; Energen’s average proppant loading is near the low end of this range at approximately 1,800 pounds in the Midland Basin and 1,900 pounds in the Delaware Basin.

The company attributes this outperformance to completing the wells in multi-zone batches instead of completing them as offset pattern wells. Utilizing simultaneous, multi-zone pattern development allows all wells to be completed at the original reservoir pressure, which should maximize reservoir productivity. In offset pattern well development, the original stand-alone well causes the reservoir pressure to drop and reduces the productivity of all subsequent wells drilled.

Bolt-on Lease Acquisitions Continue

During 3Q17, Energen closed on an additional 1,300 net acres of unproved leasehold in the Permian Basin for approximately $20 million. Year to date, Energen has acquired more than 11,000 net acres for approximately $235 million, or an average price of some $21,400 per acre. The company also has purchased 690 net mineral acres primarily in the Delaware Basin in the first nine months of 2017 for approximately $20 million.

Over the last 21 months (CY16 and YTD17), Energen’s bolt-on acquisition program has added approximately 20,300 net lease acres in prime Delaware and Midland basin locations for some $355 million, or an average price of less than $17,500 per acre.

2017 Capital Overview

Energen’s estimate of capital spending for drilling and development in 2017 remains unchanged at $850-$900 million.

Capital Summary by Basin

  2017e Capital ($MM)
Midland Basin   $ 470 - 490
Delaware Basin   $ 375 - 405
Central Basin, ARO, Other   $ 5
Drilling & Development Capital   $ 850 - 900
Acquisitions/Unproved Leasehold   $ 265
Total Capital Expenditures   $ 1,115 - 1,165
 

Liquidity and Leverage Update

The fall redetermination cycle is under way. While Energen estimates that its borrowing base will increase from $1.4 billion to $1.7 billion, the company expects its aggregate commitment under the credit facility will remain unchanged at $1.05 billion. At September 30, 2017, Energen had cash of $0.3 million, long-term debt of $527.8 million, and $238.0 million drawn on its $1.05 billion line of credit. The company estimates that net debt-to-adjusted EBITDAX at year-end 2017 will range from 1.2x-1.3x.

3Q17 Financial Results

For the 3 months ended September 30, 2017, Energen reported a GAAP net loss from all operations of $(18.5 million), or $(0.19) per diluted share. Adjusting for a non-cash loss on mark-to-market derivatives of $(40.2 million) and other miscellaneous items totaling $2.5 million, Energen had adjusted net income in 3Q17 of $19.2 million, or $0.20 per diluted share. This compares with an adjusted loss in 3Q16 of $(21.4 million), or $(0.22) per diluted share. [See “Non-GAAP Financial Measures” beginning on pp 8 for more information and reconciliation.]

Energen’s adjusted 3Q17 net income of $19.2 million exceeded internal expectations by $6.6 million largely due to better-than-expected performance of wells completed with Gen 3 fracs, less-than-expected lease operating expense (LOE) and net salaries and general and administrative expense (SG&A), and higher realized oil prices. Partially offsetting these gains was increased depreciation, depletion, and amortization expense (DD&A) largely due to increased production.

Energen’s adjusted EBITDAX totaled $174.0 million in the 3rd quarter of 2017, increased 22 percent from the second quarter, and exceeded internal expectations by 14 percent. In the same period a year ago, Energen’s adjusted EBITDAX totaled $84.8 million. [See “Non-GAAP Financial Measures” beginning on pp 8 for more information and reconciliation.]

3Q17 Production (mboepd)

Commodity   3Q17
  Actual   Guidance   % ∆
Oil   49.0   47.9   2
NGL   15.7   12.9   22
Natural Gas   16.6   13.9   19
Total   81.3   74.8   9
     
Area   3Q17
  Actual   Guidance   % ∆
Midland Basin   44.8   40.6   10  
Delaware Basin   28.7   26.2   10  
Central Basin/Other   7.9   8.0   (1 )
Total   81.3   74.8   9  

Note: Totals in production tables above may not sum due to rounding.

3Q17 Expenses

 
Per BOE, except where noted 3Q17
Actual Midpoint   % ∆
LOE (production costs, marketing & transportation)   $ 5.95   $ 7.15     (17 )

Production & ad valorem taxes (% of revenues exc. hedges)

    6.2 %   6.4 %   (3 )
DD&A   $ 17.46   $ 17.25     1  
SG&A   $ 2.87   $ 3.25     (12 )
Exploration (includes seismic, delay rentals, etc.)   $ 0.08   $ 0.13     (38 )
Interest ($mm)   $ 9.9   $ 10.0     (1 )
 

3Q17 Average Realized Prices

   
Commodity   With Hedges   W/O Hedges
Oil (per barrel)   $ 46.27   $ 45.07
NGL (per gallon)   $ 0.39   $ 0.42
Natural Gas (per mcf)   $ 2.35   $ 2.22
 

CY17 Guidance

Energen today raised its production guidance for 2017 by 4 percent to 73.2 mboepd to reflect the company’s strong 3Q17 performance as well as a 5 percent increase in its estimated 4Q17 production. Energen now expects 4Q17 volumes to reach 85.7 mboepd for an increase of 60 percent from the same period a year ago. On the strength of its Generation 3 frac design, Energen sees YOY production growth in 2017 of 34 percent, up from the prior estimate of 29 percent.

Production (mboepd)

By Basin   1Q17a   2Q17a   3Q17a   4Q17e   CY17e
Midland Basin   31.8   41.3   44.8   45.4 40.8
Delaware Basin   12.8   23.4   28.7   32.4 24.4
Central Basin Platform/Other   8.3   7.9   7.9   7.8 8.0
Total   52.8   72.5   81.3   85.7 73.2
         
By Commodity   1Q17a   2Q17a   3Q17a   4Q17e CY17e
Oil   33.3   45.1   49.0   54.0 45.4
NGL   8.9   13.5   15.7   14.9 13.3
Gas   10.6   13.9   16.6   16.8 14.5
Total   52.8   72.5   81.3   85.7 73.2

Note: Totals in production tables above may not sum due to rounding.

Operating Expenses

         
Per BOE, except where noted   1Q17a   2Q17a   3Q17a   4Q17e   CY17e
LOE*   $ 8.68   $ 6.66   $ 5.95   $6.55 - $6.85   $6.70 - $7.00
Production & ad valorem taxes**   7.3%   6.0%   6.2%   6.2%   6.4%
DD&A expense†   $ 20.71   $ 18.25   $ 17.46   $16.05 - $16.55   $17.70 - $18.10
SG&A   $ 4.29   $ 3.00   $ 2.87   $2.70 - $3.00   $3.00 - $3.30
Exploration††   $ 0.76   $ 0.30   $ 0.08   $0.15 - $0.25   $0.25 - $0.35
Interest ($mm)   $ 9.0   $ 9.1   $ 9.9   $9.5 - $10.5   $38.0 - $39.0
Effective tax rate   32%   35%   36%   36% - 38%   37% - 39%
 

* Production costs, marketing & transportation
** % of revenues, excluding hedges
4Q17 and CY17 does not include estimate of 4Q17 DD&A look-back adjustment
†† Includes seismic, delay rentals, etc.

LOE per boe in CY17 is estimated to range from $4.95-$5.25 in the Delaware Basin, $5.50-$5.80 in the Midland Basin, and $18.20-$18.50 in the Central Basin Platform. Production and ad valorem taxes in CY17, as a percent of revenues excluding hedges, are estimated to be 6.2 percent in the Delaware Basin, 6.2 percent in the Midland Basin, and 7.3 percent in the Central Basin Platform. SG&A per boe in CY17 is estimated to be comprised of cash and other of $2.55-$2.65 per boe and non-cash, equity-based compensation of $0.45-$0.65 per boe.

Hedges

Energen recently added some 1.1 mmbo of 2018 WTI Midland to WTI Cushing (sweet oil) differential hedges at an average price of $(0.60) per barrel. The company also has initiated hedging for its estimated 2019 oil production and Midland to Cushing sweet oil differential.

For the last three months of 2017, 64 percent of the company’s estimated oil production of 5.0 mmbo is hedged. Swaps for 2.0 mmbo have an average NYMEX price of $50.68 per barrel, and 3-way collars for 1.2 mmbo have average call, put, and short put prices of $62.18, $45.00, and $35.00 per barrel, respectively. Approximately 36 percent of Energen’s estimated NGL production is hedged at an average price of $0.57 per gallon, and 47 percent of its estimated gas production is hedged at an average NYMEX-equivalent price of $3.36 per Mcf. Energen also has hedged the WTI Midland to WTI Cushing (sweet oil) differential for 3.0 million barrels at an average price of $(0.68) per barrel; approximately 88 percent of Energen’s oil production for the remainder of the year is estimated to be sweet.

Basis Differentials

Energen’s average realized prices in the last three months of CY17 will reflect commodity and basis hedges, oil transportation charges of approximately $1.97 per barrel, NGL T&F fees of approximately $0.13 per gallon, and basis differentials applicable to unhedged production. Natural gas and NGL production also is subject to a percent of proceeds contract of approximately 85%.

The assumed gas basis for all open contracts for November-December 2017 is $(0.45) per Mcf, and assumed prices for unhedged Midland to Cushing basis differentials for sweet and sour oil (November-December) are $(1.00) and $(1.30), respectively. Energen’s assumed commodity prices for unhedged production are approximately $51.46 per barrel of oil (October-December), $0.76 per gallon of NGL (October-December), and $2.93 per Mcf of gas (November-December).

Estimated Price Realizations (pre-hedge):

    4Q17
Crude oil (% of NYMEX/WTI)   94
NGL (after T&F) (% of NYMEX/WTI)   44
Natural gas (% of NYMEX/Henry Hub)   72
 

2018 Hedges

Oil   2018 Hedge Volumes   Avg. NYMEX Price
Three-way Collars   13.5 mmbo    
Call Price       $ 60.04 per barrel
Put Price       $ 45.47 per barrel
Short Put Price       $ 35.47 per barrel
   
Commodity   Hedge Volumes   NYMEXe Price
NGL   105.8 mm gallons   $ 0.59 per gallon
Natural Gas   3.6 bcf   $ 3.19 per mcf

Energen also has hedged the Midland to Cushing differential on 10.8 million barrels of its estimated 2018 sweet oil production at an average price of $(1.01).

2019 Hedges

Oil   2019 Hedge Volumes   Avg. NYMEX Price
Three-way Collars   1.4 mmbo    
Call Price       $ 58.61 per barrel
Put Price       $ 45.00 per barrel
Short Put Price       $ 35.00 per barrel
   

Energen also has hedged the Midland to Cushing differential on 1.4 million barrels of its estimated 2019 sweet oil production at an average price of $(0.53).

Conference Call

3Q17 slides associated with Energen’s quarterly release and conference call are available at www.energen.com. Energen will hold its quarterly conference call Wednesday, November 8, at 8:30 a.m. EDT. Investment community members may participate by calling 1-877-407-8289 (reference Energen earnings call). A live audio Webcast of the program as well as a replay may be accessed via www.energen.com.

Energen Corporation is an oil-focused exploration and production company with operations in the Permian Basin in west Texas and New Mexico. For more information, go to www.energen.com.

FORWARD LOOKING STATEMENTS: All statements, other than statements of historical fact, appearing in this release constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements include, among other things, statements about our expectations, beliefs, intentions or business strategies for the future, statements concerning our outlook with regard to the timing and amount of future production of oil, natural gas liquids and natural gas, price realizations, the nature and timing of capital expenditures for exploration and development, plans for funding operations and drilling program capital expenditures, the timing and success of specific projects, operating costs and other expenses, proved oil and natural gas reserves, liquidity and capital resources, outcomes and effects of litigation, claims and disputes and derivative activities. Forward-looking statements may include words such as “anticipate”, “believe”, “could”, “estimate”, “expect”, “forecast”, “foresee”, “intend”, “may”, “plan”, “potential”, “predict”, “project”, “seek”, “will” or other words or expressions concerning matters that are not historical facts. These statements involve certain risks and uncertainties that may cause actual results to differ materially from expectations as of the date of this news release. Except as otherwise disclosed, the forward-looking statements do not reflect the impact of possible or pending acquisitions, investments, divestitures or restructurings. The absence of errors in input data, calculations and formulas used in estimates, assumptions and forecasts cannot be guaranteed. We base our forward-looking statements on information currently available to us, and we undertake no obligation to correct or update these statements whether as a result of new information, future events or otherwise. Additional information regarding our forward‐looking statements and related risks and uncertainties that could affect future results of Energen, can be found in the Company’s periodic reports filed with the Securities and Exchange Commission and available on the Company’s website - www.energen.com.

CAUTIONARY STATEMENTS: The SEC permits oil and gas companies to disclose in SEC filings only proved, probable and possible reserves that meet the SEC’s definitions for such terms, and price and cost sensitivities for such reserves, and prohibits disclosure of resources that do not constitute such reserves. Outside of SEC filings, we use the terms “estimated ultimate recovery” or “EUR,” reserve or resource “potential,” “contingent resources” and other descriptions of volumes of non-proved reserves or resources potentially recoverable through additional drilling or recovery techniques. These estimates are inherently more speculative than estimates of proved reserves and are subject to substantially greater risk of actually being realized. We have not risked EUR estimates, potential drilling locations, and resource potential estimates. Actual locations drilled and quantities that may be ultimately recovered may differ substantially from estimates. We make no commitment to drill all of the drilling locations that have been attributed these quantities. Factors affecting ultimate recovery include the scope of our on-going drilling program, which will be directly affected by the availability of capital, drilling, and production costs, availability of drilling and completion services and equipment, drilling results, lease expirations, regulatory approvals, and geological and mechanical factors. Estimates of unproved reserves, type/decline curves, per-well EURs, and resource potential may change significantly as development of our oil and gas assets provides additional data. Additionally, initial production rates contained in this news release are subject to decline over time and should not be regarded as reflective of sustained production levels.

Financial, operating, and support data pertaining to all reporting periods included in this release are
unaudited and subject to revision.

Non-GAAP Financial Measures

 
Adjusted Net Income is a Non-GAAP financial measure (GAAP refers to generally accepted accounting principles) which excludes the effects of certain non-cash mark-to-market derivative financial instruments. Adjusted income from continuing operations further excludes impairment losses, certain prior period losses associated with a reduction in force, and income associated with divestitures. Energen believes that excluding the impact of these items is more useful to analysts and investors in comparing the results of operations and operational trends between reporting periods and relative to other oil and gas producing companies.
 
  Three Months Ended 9/30/17  
Energen Net Income ($ in millions except per share data)   Net Income  

Per Diluted
Share

 
Net Income (Loss) All Operations (GAAP) (18.5 )     (0.19 )  
Non-cash mark-to-market losses (net of $22.1 tax) 40.2 0.41
Asset impairment, other (net of tax) 0.1 nm
Income associated with property sales (net of $2.0 tax)  

(2.5

)

 

 

 

(0.03

)

 

 

Adjusted Income from Continuing Operations (Non-GAAP)   19.2         0.20      
 
               
Three Months Ended 9/30/16  
Energen Net Income ($ in millions except per share data)   Net Income  

Per Diluted
Share

 
Net Income (Loss) All Operations (GAAP) 53.3 0.55
Non-cash mark-to-market gains (net of $8.9 tax) (16.1 ) (0.17 )
Asset impairment, other (net of $0.3 tax) 0.3 nm
Reduction in force expenses (net of $0.2 tax) 0.3 nm
Income associated property sales (net of $32.3 tax)   (59.2 )       (0.61 )    
Adjusted Income from Continuing Operations (Non-GAAP)   (21.4 )       (0.22 )    
 
Note: Amounts may not sum due to rounding
 
 

Non-GAAP Financial Measures

 
Earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses (EBITDAX) is a Non-GAAP financial measure (GAAP refers to generally accepted accounting principles). Adjusted EBITDAX from continuing operations further excludes impairment losses, certain non-cash mark-to-market derivative financial instruments, prior period losses associated with a reduction in force, and income associated with divestitures. Energen believes these measures allow analysts and investors to understand the financial performance of the company from core business operations, without including the effects of capital structure, tax rates and depreciation. Further, this measure is useful in comparing the company and other oil and gas producing companies.
 
         
Reconciliation To GAAP Information Three Months Ended 9/30  
($ in millions)   2017     2016  
 
Energen Net Income (Loss) (GAAP) (18.5 ) 53.3
Income associated with property sales, net of tax*   (2.5 )   (59.2 )
Net Income (Loss) Excluding Property Sales (Non-GAAP)   (21.0 )   (5.9 )
Interest expense 9.9 9.0
Income tax expense (benefit) ** (11.2 ) (3.9 )
Depreciation, depletion and amortization ** 131.8 108.0
Accretion expense ** 1.5 1.6
Exploration expense ** 0.6 nm
Adjustment for asset impairment 0.1 0.6
Adjustment for mark-to-market (gains)/ losses 62.3 (25.0 )
Adjustment for reduction in force expenses   0.0     0.5  
Energen Adjusted EBITDAX from Continuing Operations (Non-GAAP)   174.0     84.8  
 
 
Note: Amounts may not sum due to rounding
 
*For quarter to quarter comparability, excluded from GAAP income in the current quarter is an immaterial sale of certain unproved leasehold properties in Wyoming.
 
 
 
** Amount adjusted to exclude 2016 property sales in prior period. See reconciliation to GAAP Information for the Three Months Ended 9/30/2016.
 

Non-GAAP Financial Measures

 
The consolidated statement of income excluding certain divestments is a Non-GAAP financial measure (GAAP refers to generally accepted accounting principles). Energen believes excluding information associated with 2016 property sales provides analysts and investors useful information to understand the financial performance of the company from ongoing business operations. Further, this information is useful in comparing the company and other oil and gas producing companies operating primarily in the Permian Basin.
 
   
Energen Net Income (Loss) Excluding 2016 Property Sales

Reconciliation to GAAP Information

Three Months Ended
September 30, 2016

(in thousands except per share and production data)            
GAAP   2016 Property Sales   Non-GAAP
Revenues
Oil, natural gas liquids and natural gas sales $ 163,973 $ 2,162 $ 161,811
Gain (loss) on derivative instruments     20,412       -         20,412  
Total Revenues     184,385       2,162         182,223  
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production 42,280 1,253 41,027
Production and ad valorem taxes 10,987 621 10,366
O&G Depreciation, depletion and amortization 106,989 215 106,774
FF&E Depreciation, depletion and amortization 1,178 - 1,178
Asset impairment 587 - 587
Exploration 18 6 12
General and administrative † 21,710 (53 ) 21,763
Accretion of discount on asset retirement obligations 1,556 1 1,555
(Gain) loss on sale of assets and other     (91,222 )     (91,371 )       149  
Total costs and expenses     94,083       (89,328 )       183,411  
Operating Income (Loss)     90,302       91,490         (1,188 )
Other Income/(Expense)
Interest expense (8,987 ) - (8,987 )
Other income     421       12         409  
Total other expense     (8,566 )     12         (8,578 )
 
Loss Before Income Taxes 81,736 91,502 (9,766 )
Income tax expense (benefit)     28,422       32,289         (3,867 )
Net Income (Loss)   $ 53,314     $ 59,213       $ (5,899 )
               
Diluted Earnings Per Average Common Share   $ 0.55     $ 0.60       $ (0.06 )
               
Basic earning Per Average Common Share   $ 0.55     $ 0.60       $ (0.06 )
 
Oil 3,325 30 3,295
NGL 980 22 958
Natural Gas     993       43         950  
Total Production (mboe)     5,298       95         5,203  
Total Production (boepd)     57,587       1,033         56,554  
 
Note: Amounts may not sum due to rounding
 
† General and administrative includes $515 of expense related to the reductions in force

   

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

For the 3 months ending September 30, 2017 and 2016

 
3rd Quarter
 
(in thousands, except per share data)     2017       2016       Change
 
Revenues
Oil, natural gas liquids and natural gas sales $ 249,114 $ 163,973 $ 85,141
Gain (loss) on derivative instruments, net     (57,610 )     20,412       (78,022 )
 
Total revenues     191,504       184,385       7,119  
 
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production 44,549 42,280 2,269
Production and ad valorem taxes 15,326 10,987 4,339
Depreciation, depletion and amortization 131,756 108,167 23,589
Asset impairment 100 587 (487 )
Exploration 625 18 607

General and administrative (including stock based compensation of $4,713 and $6,518 for the three months ended September 30, 2017, and 2016, respectively)

21,474

21,710

(236

)

Accretion of discount on asset retirement obligations 1,473 1,556 (83 )
Gain on sale of assets and other     (5,977 )     (91,222 )     85,245  
 
Total operating costs and expenses     209,326       94,083       115,243  
 
Operating Income (Loss)     (17,822 )     90,302       (108,124 )
 
Other Income (Expense)
Interest expense (9,928 ) (8,987 ) (941 )
Other income     58       421       (363 )
 
Total other expense     (9,870 )     (8,566 )     (1,304 )
 
Income (Loss) Before Income Taxes (27,692 ) 81,736 (109,428 )
Income tax expense (benefit)     (9,206 )     28,422       (37,628 )
 
Net Income (Loss)   $ (18,486 )   $ 53,314     $ (71,800 )
                   
Diluted Earnings Per Average Common Share   $ (0.19 )   $ 0.55     $ (0.74 )
Basic Earnings Per Average Common Share   $ (0.19 )   $ 0.55     $ (0.74 )
Diluted Average Common Shares Outstanding     97,198       97,511       (313 )
Basic Average Common Shares Outstanding     97,198       97,068       130  

   

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

For the 9 months ending September 30, 2017 and 2016

 
Year-to-date
 
(in thousands, except per share data)     2017       2016       Change
 
Revenues
Oil, natural gas liquids and natural gas sales $ 644,212 $ 458,374 $ 185,838
Gain (loss) on derivative instruments, net     45,037       (40,005 )     85,042  
 
Total revenues     689,249       418,369       270,880  
 
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production 129,746 132,847 (3,101 )
Production and ad valorem taxes 41,364 33,422 7,942
Depreciation, depletion and amortization 352,957 344,564 8,393
Asset impairment 1,589 220,612 (219,023 )
Exploration 6,259 1,780 4,479

General and administrative (including stock based compensation of $11,101 and $14,493 for the nine months ended September 30, 2017, and 2016, respectively)

61,665

74,783

(13,118

)

Accretion of discount on asset retirement obligations 4,330 5,092 (762 )
Gain on sale of assets and other     (6,980 )     (252,097 )     245,117  
 
Total operating costs and expenses     590,930       561,003       29,927  
 
Operating Income (Loss)     98,319       (142,634 )     240,953  
 
Other Income (Expense)
Interest expense (28,039 ) (27,858 ) (181 )
Other income     486       580       (94 )
 
Total other expense     (27,553 )     (27,278 )     (275 )
 
Income (Loss) Before Income Taxes 70,766 (169,912 ) 240,678
Income tax expense (benefit)     26,368       (56,869 )     83,237  
 
Net Income (Loss)   $ 44,398     $ (113,043 )   $ 157,441  
                   
Diluted Earnings Per Average Common Share   $ 0.45     $ (1.21 )   $ 1.66  
Basic Earnings Per Average Common Share   $ 0.46     $ (1.21 )   $ 1.67  
Diluted Average Common Shares Outstanding     97,678       93,602       4,076  
Basic Average Common Shares Outstanding     97,176       93,602       3,574  
   

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

As of September 30, 2017 and December 31, 2016

 
(in thousands)     September 30, 2017       December 31, 2016
 
 
ASSETS
Current Assets
Cash and cash equivalents $ 252 $ 386,093
Accounts receivable, net 129,219 73,322
Inventories, net 14,538 14,222
Derivative instruments 3,895 50
Income tax receivable 9,598 27,153
Prepayments and other     5,838       5,071
 
Total current assets     163,340       505,911
 
Property, Plant and Equipment
Oil and natural gas properties, net 4,633,512 4,016,683
Other property and equipment, net     45,198       44,869
 
Total property, plant and equipment, net     4,678,710       4,061,552
 
Other postretirement assets 3,583 3,619
Noncurrent derivative instruments 1,064
Other assets 6,879 8,741
 
TOTAL ASSETS $ 4,853,576 $ 4,579,823
 

LIABILITIES AND SHAREHOLDERS’ EQUITY

   
Current Liabilities
Long-term debt due within one year $ $ 24,000
Accounts payable 101,819 65,031
Accrued taxes 14,585 7,252
Accrued wages and benefits 21,268 25,089
Accrued capital costs 67,176 79,988
Revenue and royalty payable 48,429 51,217
Derivative instruments 18,089 65,467
Other     11,402         20,160
 
Total current liabilities     282,768         338,204
 
Long-term debt 765,759 527,443
Asset retirement obligations 86,643 81,544
Deferred income taxes 535,002 495,888
Noncurrent derivative instruments 2,962 3,006
Other long-term liabilities     7,162         13,136
 
Total liabilities     1,680,296         1,459,221
 
Total Shareholders’ Equity     3,173,280         3,120,602
 
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY   $ 4,853,576     $   4,579,823
 

   

SELECTED BUSINESS SEGMENT DATA (UNAUDITED)

For the 3 months ending September 30, 2017 and 2016

3rd Quarter
(in thousands, except sales price and per unit data)     2017     2016     Change
 
Operating and production data
Oil, natural gas liquids and natural gas sales
Oil $ 203,281 $ 138,388 $ 64,893
Natural gas liquids 25,508 12,067 13,441
Natural gas     20,325     13,518     6,807
Total   $ 249,114   $ 163,973   $ 85,141
 
 
Open non-cash mark-to-market gains (losses) on derivative instruments
Oil $ (46,395) $ 22,984 $ (69,379)
Natural gas liquids (15,765) (954) (14,811)
Natural gas     (105)     2,992     (3,097)
Total   $ (62,265)   $ 25,022   $ (87,287)
 
Closed gains (losses) on derivative instruments
Oil $ 5,388 $ (4,118) $ 9,506
Natural gas liquids (1,923) (1,923)
Natural gas     1,190     (492)     1,682
Total   $ 4,655   $ (4,610)   $ 9,265
Total revenues   $ 191,504   $ 184,385   $ 7,119
 
Production volumes
Oil (MBbl) 4,510 3,325 1,185
Natural gas liquids (MMgal) 60.6 41.2 19.4
Natural gas (MMcf)     9,174     5,958     3,216
Total production volumes (MBOE) 7,483     5,298     2,185
 
Average daily production volumes
Oil (MBbl/d) 49.0 36.1 12.9
Natural gas liquids (MMgal/d) 0.7 0.4 0.3
Natural gas (MMcf/d)     99.7     64.8     34.9
Total average daily production volumes (MBOE/d)     81.3     57.6     23.7
 
Average realized prices excluding effects of open non-cash mark-to-market derivative instruments
Oil (per barrel) $ 46.27 $ 40.38 $ 5.89
Natural gas liquids (per gallon) $ 0.39 $ 0.29 $ 0.10
Natural gas (per Mcf) $ 2.35 $ 2.19 $ 0.16
 
Average realized prices excluding effects of all derivative instruments
Oil (per barrel) $ 45.07 $ 41.62 $ 3.45
Natural gas liquids (per gallon) $ 0.42 $ 0.29 $ 0.13
Natural gas (per Mcf) $ 2.22 $ 2.27 $ (0.05)
 
Costs per BOE
Oil, natural gas liquids and natural gas production expenses

$

5.95

$

7.98

$

(2.03)

Production and ad valorem taxes $ 2.05 $ 2.07 $ (0.02)
Depreciation, depletion and amortization $ 17.61 $ 20.42 $ (2.81)
Exploration expense $ 0.08 $ $ 0.08
General and administrative $ 2.87 $ 4.10 $ (1.23)
Capital expenditures (including acquisitions)   $ 251,621   $ 211,393   $ 40,228
 
   

SELECTED BUSINESS SEGMENT DATA (UNAUDITED)

For the 9 months ending September 30, 2017 and 2016

 
Year-to-date
 
(in thousands, except sales price and per unit data)     2017     2016     Change
 
 
Operating and production data
Oil, natural gas liquids and natural gas sales
Oil $ 532,652 $ 386,905 $ 145,747
Natural gas liquids 59,776 34,584 25,192
Natural gas     51,784     36,885     14,899
Total   $ 644,212   $ 458,374   $ 185,838
 
 
Open non-cash mark-to-market gains (losses) on derivative instruments
Oil $ 42,730 $ (33,444) $ 76,174
Natural gas liquids (4,148) (954) (3,194)
Natural gas     8,856     (1,462)     10,318
Total   $ 47,438   $ (35,860)   $ 83,298
 
Closed gains (losses) on derivative instruments
Oil $ (470) $ (5,321) $ 4,851
Natural gas liquids (3,468) (3,468)
Natural gas     1,537     1,176     361
Total   $ (2,401)   $ (4,145)   $ 1,744
Total revenues   $ 689,249   $ 418,369   $ 270,880
 
Production volumes
Oil (MBbl) 11,608 10,269 1,339
Natural gas liquids (MMgal) 146.0 126.0 20.0
Natural gas (MMcf)     22,500     20,700     1,800
Total production volumes (MBOE)     18,833     16,719     2,114
 
Average daily production volumes
Oil (MBbl/d) 42.5 37.5 5.0
Natural gas liquids (MMgal/d) 0.5 0.5
Natural gas (MMcf/d)     82.4     75.5     6.9
Total average daily production volumes (MBOE/d)     69.0     61.0     8.0
 
Average realized prices excluding effects of open non-cash mark-to-market derivative instruments
Oil (per barrel) $ 45.85 $ 37.16 $ 8.69
Natural gas liquids (per gallon) $ 0.39 $ 0.27 $ 0.12
Natural gas (per Mcf) $ 2.37 $ 1.84 $ 0.53
 
Average realized prices excluding effects of all derivative instruments
Oil (per barrel) $ 45.89 $ 37.68 $ 8.21
Natural gas liquids (per gallon) $ 0.41 $ 0.27 $ 0.14
Natural gas (per Mcf) $ 2.30 $ 1.78 $ 0.52
 
Costs per BOE
Oil, natural gas liquids and natural gas production expenses

$

6.89

$

7.94

$

(1.05)

Production and ad valorem taxes $ 2.20 $ 2.00 $ 0.20
Depreciation, depletion and amortization $ 18.74 $ 20.61 $ (1.87)
Exploration expense $ 0.33 $ 0.11 $ 0.22
General and administrative $ 3.27 $ 4.47 $ (1.20)
Capital expenditures (includes acquisitions)   $ 971,867   $ 428,443   $ 543,424

Source: Energen Corporation

Energen Corporation
Julie S. Ryland, 205-326-8421



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