Energen’s New Gen 3 Wells Delivering Outstanding Results in All Key Areas of Permian Operations
Energen Corporation (NYSE: EGN) (“Energen” or the “company”) today announced financial and operating results for the second quarter ended June 30, 2017.
FINANCIAL AND OPERATING HIGHLIGHTS
2Q17
- Production beats June revised guidance by 2% and May guidance by 17%
- On track to generate 29% YOY growth in total production and 37% YOY growth in Midland and Delaware production
- Adjusted EBITDAX grows 49% from 1Q17 and beats internal expectations
- Per-unit LOE (including marketing and transportation) beats June revised guidance midpoint by 8.1%
- Per unit SG&A beats June revised guidance midpoint by 10.4%
- Lease acquisitions in first six months of 2017 total 9,732 net acres for ≈$215 mm
- Energen adds 158 net locations to Wolfcamp/Spraberry/Cline inventory and identifies 413 net locations in other Delaware Basin formations for total identified inventory of 4,116 net locations
2Q17 WELL RESULTS
- 45 gross and net wells in the Midland and Delaware basins were turned to production in 2Q17 and generated excellent initial production rates in all key areas of operational focus in 2017; 78% are multi-zone pattern wells completed in batches
- 59 Gen 3 wells are outperforming the highest EUR type curve and significantly outperforming the midpoint EUR type curve; 76% are multi-zone pattern wells completed in batches
- Public data shows Gen 3 wells in Midland and Delaware basins outperforming other operators’ wells
Comments from the CEO
“The success we are achieving with our Generation 3 frac design and multi-zone pattern wells completed in batches has set the stage for 2017 to be the break-out year we have been working toward, underscoring our top-tier assets and solid execution,” said Energen Chief Executive Officer James McManus. “We are delivering outstanding well performance in all our areas of operational focus in the Midland and Delaware basins; and we continue to drive down our operating costs and G&A and are competitive with the best in the Midland and Delaware basins.
“Importantly, our Gen 3 wells are outperforming wells completed by other operators. The public well data also supports our position that the best way to maximize the full development of our assets is to complete them in multi-zone batches at original reservoir pressure,” McManus said. “We expect our Gen 3 multi-zone pattern wells to continue driving production growth as we move forward.
“We have continued executing on our bolt-on acquisition program, which we believe has created significant value for Energen. Over the last 18 months, we have added approximately 19,000 net acres in prime Delaware and Midland basin locations for an average price of about $17,600 an acre,” McManus said. “This includes some 9,700 net acres acquired in the first six months of this year that helped contribute to an increase in our inventory of identified locations.
“We are pleased with our performance this quarter and excited about our future prospects as we successfully implement our 2017 drilling and development program. We plan to maintain our focus on the further optimization of well performance and returns, and we are confident that Energen is well-positioned to continue delivering strong results and creating shareholder value in 2017 and beyond.”
Operations Update
In the second quarter of 2017, Energen turned to production 27 gross (27 net) wells in the Midland Basin and 18 gross (18 net) wells in the Delaware Basin; 78 percent are multi-zone pattern wells completed in batches. The company operated an average of 6.5 horizontal drilling rigs and an average of 4 frac crews. In the first six months of 2017, Energen turned to production 49 net wells in its 60-net well DUC inventory at year-end 2016.
2017 First Production/Flow back (Horizontal Wells – Gross/Net) |
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1Q17a | 2Q17a | 3Q17e | 4Q17e | CY17e | |||||||||||
Midland Basin | 10/9 | 27/27 | 20/19 | 19/14 | 76/69 | ||||||||||
Delaware Basin | 2/2 | 18/18 | 3/3 | 12/12 | 35/35 | ||||||||||
2Q17 Wells Turned to Production |
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Area | # of Wells |
Average |
Avg. Peak 24-Hour IP | Avg. Peak 30-day IP | |||||||||||||||||
Boepd | %Oil | Boepd | %Oil | ||||||||||||||||||
Delaware Basin | 18 |
Wolfcamp A (8)
Wolfcamp B (10) |
9,466’ | 2,338 | 59 | 1,8891 |
60 |
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Northern Midland Basin | 11 |
MSB (4), Jo Mill (3), |
10,531’ | 1,250 | 88 | 1,2122 | 85 | ||||||||||||||
Northern Midland Basin | 8 |
Wolfcamp A (3)
Wolfcamp B (5) |
10,510’ | 1,558 | 86 | 1,270 3 | 81 | ||||||||||||||
Central Midland Basin | 8 |
Wolfcamp A (3) Wolfcamp B (5) |
7,502’ | 1,671 | 79 | 1,126 | 66 | ||||||||||||||
1 16 wells with 30-day data |
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2 4 wells with 30-day data |
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3 7 wells with 30-day data |
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For 59 of the Gen 3 wells drilled to date (76 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 exceeding 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:
- ≈31% over a 1.75 MMBOE type curve at 270 days for 20 Delaware Basin Wolfcamp A and B wells – 9 of 20 are multi-zone pattern wells completed in batches
- ≈40% over a 1.2 MMBOE type curve at 90 days for 11 wells in the Spraberry package – all are multi-zone pattern wells completed in batches
- ≈11% over a 1.2 MMBOE type curve at 240 days for 10 northern Midland Basin Wolfcamp A and B wells – 7 of 10 are multi-zone pattern wells completed in batches
- ≈21% over a 1.2 MMBOE type curve at 170 days for 16 central Midland Basin Wolfcamp A and B wells – all are multi-zone pattern wells in batches
- ≈47% over a 850 MBOE type curve at 160 days for 2 central Midland Basin Lower Spraberry wells – both 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 is outperforming 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 comparable proppant loads of 1,700-2,500 pounds per foot.
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, Inventory Grows
In the first six months of 2017, Energen has acquired more than 9,700 net acres for approximately $215 million, or an average price of some $22,000 per acre. These acquisitions helped contribute to the addition of 158 net locations in its Wolfcamp, Spraberry, and Cline inventory (after moving 32 net locations into the drilled category). The company also has identified 413 net locations in other Delaware Basin formations, giving the company a new identified inventory of 4,116 net locations.
The company also has purchased 690 net mineral acres in the Delaware Basin in the first six months of 2017 for approximately $20 million.
Over the last 18 months (CY16 and YTD17), the company’s bolt-on acquisition program has added approximately 19,000 net lease acres in prime Delaware and Midland basin locations for an average price of approximately $17,600 an 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 | $ | 235 | ||
Total Capital Expenditures | $ | 1,085 - 1,135 | ||
Liquidity and Leverage Update
As of June 30, 2017, Energen had cash of $0.5 million, long-term debt of $544.7 million, and $131.5 million drawn on its $1.05 billion line of credit, and its borrowing base currently is $1.4 billion. Energen estimates that its year-end 2017 total net debt-to-2017 adjusted EBITDAX will range from 1.3x - 1.4x.
2Q17 Financial Results
For the 3 months ended June 30, 2017, Energen reported GAAP net income from all operations of $29.5 million, or $0.30 per diluted share. Adjusting for a non-cash gain on mark-to-market derivatives and a small, non-cash impairment loss, Energen had adjusted net income in 2Q17 of $5.4 million, or $0.06 per diluted share. This compares with an adjusted loss in 2Q16 of $(27.1 million), or $(0.28) per diluted share. [See “Non-GAAP Financial Measures” beginning on pp 8 for more information and reconciliation.]
Energen’s adjusted 2Q17 net income of $5.4 million exceeded internal expectations by $1.6 million largely due to:
- Less-than-expected lease operating expense (LOE) largely due to lower power and chemical costs;
- Higher production due to continued positive impact of Gen 3 completions;
- Lower salaries and general and administrative expense (SG&A) primarily due to lower non-cash compensation; and
- Decreased production and ad valorem taxes.
Partially offsetting these gains were lower realized sales prices and increased depreciation, depletion, and amortization expense (DD&A) largely due to increased production.
Energen’s adjusted EBITDAX totaled $142.4 million in the 2nd quarter of 2017, increased 49 percent from the first quarter, and exceeded internal expectations by 4 percent. In the same period a year ago, Energen’s adjusted EBITDAX totaled $82.3 million. [See “Non-GAAP Financial Measures” beginning on pp 8 for more information and reconciliation.]
Commodity | 2Q17 | 1Q17 | ||||||||||||||||||||
Actual |
June Rev. |
% ∆ |
May |
% ∆ | ||||||||||||||||||
Oil | 45.1 | 44.9 | 0 | 40.6 | 11 | 33.3 | ||||||||||||||||
NGL | 13.5 | 12.8 | 5 | 10.5 | 29 | 8.9 | ||||||||||||||||
Natural Gas | 13.9 | 13.5 | 3 | 11.1 | 25 | 10.6 | ||||||||||||||||
Total | 72.5 | 71.1 | 2 | 62.2 | 17 | 52.8 | ||||||||||||||||
Area | 2Q17 | 1Q17 | ||||||||||||||||||||
Actual |
June Rev. |
% ∆ |
May |
% ∆ | ||||||||||||||||||
Midland Basin | 41.3 | 40.5 | 2 | 34.2 | 21 | 31.8 | ||||||||||||||||
Delaware Basin | 23.4 | 22.9 | 2 | 19.8 | 18 | 12.8 | ||||||||||||||||
Central Basin/Other | 7.9 | 7.7 | 3 | 8.2 | (4) | 8.3 | ||||||||||||||||
Total | 72.5 | 71.1 | 2 | 62.2 | 17 | 52.8 | ||||||||||||||||
Note: Totals in production tables above may not sum due to rounding. |
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2Q17 Expenses |
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Per BOE, except where noted | 2Q17 | 1Q17 | ||||||||||||
Actual |
June Guidance |
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LOE (production costs, marketing & transportation) | $ | 6.66 | $ | 7.25 | $ | 8.68 | ||||||||
Production & ad valorem taxes (% of revenues exc. hedges) |
6.0% | 6.9% | 7.3% | |||||||||||
DD&A | $ | 18.25 | $ | 18.30 | $ | 20.71 | ||||||||
SG&A | $ | 3.00 | $ | 3.35 | $ | 4.29 | ||||||||
Exploration (includes seismic, delay rentals, etc.) | $ | 0.30 | $ | 0.25 | $ | 0.76 | ||||||||
Interest ($mm) | $ | 9.1 | $ | 9.2 | $ | 9.0 | ||||||||
2Q17 Average Realized Prices |
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Commodity | With Hedges | W/O Hedges | ||||||
Oil (per barrel) | $ | 44.58 | $ | 44.54 | ||||
NGL (per gallon) | $ | 0.36 | $ | 0.36 | ||||
Natural Gas (per mcf) | $ | 2.38 | $ | 2.29 | ||||
CY17 Guidance
Production (mboepd) |
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By Basin | 1Q17a | 2Q17a | 3Q17e | 4Q17e | CY17e | ||||||||||||
Midland Basin | 31.8 | 41.3 | 40.6 | 42.1 | 39.0 | ||||||||||||
Delaware Basin | 12.8 | 23.4 | 26.2 | 31.9 | 23.6 | ||||||||||||
Central Basin Platform/Other | 8.3 | 7.9 | 8.0 | 7.8 | 8.0 | ||||||||||||
Total | 52.8 | 72.5 | 74.8 | 81.9 | 70.6 | ||||||||||||
By Commodity | 1Q17a | 2Q17a | 3Q17e | 4Q17e | CY17e | ||||||||||||
Oil | 33.3 | 45.1 | 47.9 | 53.4 | 45.0 | ||||||||||||
NGL | 8.9 | 13.5 | 12.9 | 13.7 | 12.3 | ||||||||||||
Gas | 10.6 | 13.9 | 13.9 | 14.7 | 13.3 | ||||||||||||
Total | 52.8 | 72.5 | 74.8 | 81.9 | 70.6 | ||||||||||||
Note: Totals in production tables above may not sum due to rounding. |
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Operating Expenses |
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Per BOE, except where noted | 1Q17a | 2Q17a | 3Q17e | 4Q17e | CY17e | ||||||||||||
LOE* | $ | 8.68 | $ | 6.66 | $7.00-$7.30 | $6.85-$7.15 | $7.05-$7.45 | ||||||||||
Production & ad valorem taxes** | 7.3% | 6.0% | 6.4% | 6.3% | 6.5% | ||||||||||||
DD&A expense† | $ | 20.71 | $ | 18.25 | $17.05-$17.45 | $15.25-$15.75 | $17.45-$17.85 | ||||||||||
SG&A | $ | 4.29 | $ | 3.00 | $3.10-$3.40 | $2.55-$2.85 | $3.00-$3.40 | ||||||||||
Exploration†† | $ | 0.76 | $ | 0.30 | $0.10-$0.15 | $0.15-$0.20 | $0.25-$0.35 | ||||||||||
Interest ($mm) | $ | 9.0 | $ | 9.1 | $9.5-$10.5 | $10.0-$11.0 | $38.5-$39.5 | ||||||||||
Effective tax rate | 32% | 35% | 37%-39% | 36%-38% | 37%-39% | ||||||||||||
* Production costs, marketing & transportation |
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** % of revenues, excluding hedges |
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† 4Q17 and CY17 does not include estimate of 4Q17 DD&A look-back adjustment |
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†† Includes seismic, delay rentals, etc. |
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LOE per boe in CY17 is estimated to range from $5.20-$5.50 in the Delaware Basin, $5.85-$6.15 in the Midland Basin, and $18.60-$18.90 in the Central Basin Platform. Production and ad valorem taxes in CY17, as a percent of revenues excluding hedges, are estimated to be 6.3 percent in the Delaware Basin, 6.4 percent in the Midland Basin, and 7.4 percent in the Central Basin Platform. SG&A per boe in CY17 is estimated to be comprised of cash and other of $2.50-$2.70 per boe and non-cash, equity-based compensation of $0.50-$0.70 per boe.
Hedges
For the last six months of 2017, 69 percent of the company’s estimated oil production of 9.3 mmbo is hedged. Swaps for 4.0 mmbo have an average NYMEX price of $50.68 per barrel, and 3-way collars for 2.4 mmbo have average call, put, and short put prices of $62.18, $45.00, and $35.00 per barrel, respectively. Approximately 40 percent of Energen’s estimated NGL production is hedged at an average price of $0.57 per gallon, and 55 percent of its estimated gas production is hedged at an average NYMEX-equivalent price of $3.31 per Mcf. Energen also has hedged the WTI Midland to WTI Cushing (sweet oil) differential for 5.6 million barrels at an average price of $(0.66) per barrel; approximately 87 percent of Energen’s oil production for the remainder of the year is estimated to be sweet.
In 3Q17, approximately 73 percent of the company’s estimated oil production of 4.4 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 42 percent of Energen’s estimated NGL production is hedged at an average price of $0.57 per gallon, and 57 percent of its estimated gas production is hedged at an average NYMEXe price of $3.30 per Mcf. Energen also has hedged the Midland to Cushing differential for 2.6 million barrels at an average price of $(0.64) per barrel; approximately 68 percent of Energen’s estimated oil production in 3Q17 is estimated to be sweet.
Basis Differentials
Energen’s average realized prices in the last six months of CY17 will reflect commodity and basis hedges, oil transportation charges of approximately $2.00 per barrel, NGL T&F fees of approximately $0.12 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 August-December 2017 is $(0.45) per Mcf, and assumed prices for unhedged Midland to Cushing basis differentials for sweet and sour oil (August-December) are $(1.45) and $(1.30), respectively. Energen’s assumed commodity prices for unhedged production are approximately $47.30 per barrel of oil (July-December), $0.60 per gallon of NGL (July-December), and $3.15 per Mcf of gas (August-December).
Estimated Price Realizations (pre-hedge): |
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3Q17 | ROY 2017 | |||||
Crude oil (% of NYMEX/WTI) | 93 | 93 | ||||
NGL (after T&F) (% of NYMEX/WTI) | 37 | 34 | ||||
Natural gas (% of NYMEX/Henry Hub) | 74 | 74 | ||||
2018 Hedges |
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Oil | 2018 Hedge Volumes | Avg. NYMEX Price | ||||
Three way Collars | 13.5 mmbo | |||||
Call Price |
$ 60.04 per barrel |
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Put Price |
$ 45.47 per barrel |
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Short Put Price |
$ 35.47 per barrel |
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Commodity | Hedge Volumes | NYMEXe Price | ||||
NGL | 105.8 mm gallons | $ 0.59 per gallon | ||||
Natural Gas | 3.6 bcf | $ 3.10 per mcf | ||||
Energen also has hedged the Midland to Cushing differential on 7.6 million barrels of its estimated 2018 sweet oil production at an average price of $(1.10).
Conference Call
2Q17 slides associated with Energen’s quarterly release and conference call are available at www.energen.com. Energen will hold its quarterly conference call Tuesday, August 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. |
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Three Months Ended 6/30/17 | ||||||||
Energen Net Income ($ in millions except per share data) | Net Income |
Per Diluted |
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Net Income (Loss) All Operations (GAAP) | 29.5 | 0.30 | ||||||
Non-cash mark-to-market gains (net of $13.2 tax) | (24.1 | ) | (0.25 | ) | ||||
Asset impairment, other (net of tax) | nm | nm | ||||||
Adjusted Income from Continuing Operations (Non-GAAP) | 5.4 | 0.06 | ||||||
Three Months Ended 6/30/16 | ||||||||
Energen Net Income ($ in millions except per share data) | Net Income |
Per Diluted |
||||||
Net Income (Loss) All Operations (GAAP) | 36.8 | 0.38 | ||||||
Non-cash mark-to-market losses (net of $21.5 tax) | 39.1 | 0.40 | ||||||
Reduction in force expenses (net of $0.3 tax) | 0.6 | 0.01 | ||||||
Income associated with 2016 property sales (net of $58.2 tax) | (103.5 | ) | (1.06 | ) | ||||
Adjusted Income from Continuing Operations (Non-GAAP) | (27.1 | ) | (0.28 | ) | ||||
Note: Amounts may not sum due to rounding | ||||||||
Non-GAAP Financial Measures
Earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses (EBITDAX) is a Non-GAAP financial measure (GAAP refers to generally accepted accounting principles). Adjusted EBITDAX from continuing operations further excludes impairment losses, certain non-cash mark-to-market derivative financial instruments, prior period losses associated with a reduction in force, and income associated with divestitures. Energen believes these measures allow analysts and investors to understand the financial performance of the company from core business operations, without including the effects of capital structure, tax rates and depreciation. Further, this measure is useful in comparing the company and other oil and gas producing companies. |
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Reconciliation To GAAP Information | Three Months Ended 6/30 | |||||||
($ in millions) | 2017 | 2016 | ||||||
Energen Net Income (Loss) (GAAP) | 29.5 | 36.8 | ||||||
Income associated with 2016 property sales, net of tax | 0.0 | (103.5 | ) | |||||
Net Income (Loss) Excluding 2016 Property Sales (Non-GAAP) | 29.5 | (66.8 | ) | |||||
Interest expense | 9.1 | 9.0 | ||||||
Income tax expense (benefit) * | 16.1 | (35.1 | ) | |||||
Depreciation, depletion and amortization * | 121.5 | 110.6 | ||||||
Accretion expense * | 1.4 | 1.5 | ||||||
Exploration expense * | 2.0 | 1.5 | ||||||
Adjustment for asset impairment | nm | 0.0 | ||||||
Adjustment for mark-to-market (gains)/ losses | (37.3 | ) | 60.6 | |||||
Adjustment for reduction in force expenses | 0.0 | 0.9 | ||||||
Energen Adjusted EBITDAX from Continuing Operations (Non-GAAP) | 142.4 | 82.3 | ||||||
Note: Amounts may not sum due to rounding | ||||||||
* Amount adjusted to exclude property sales in prior period. See reconciliation to GAAP Information for the Three Months Ended 6/30/16. |
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. |
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Energen Net Income (Loss) Excluding 2016 Property Sales | |||||||||||||||
Reconciliation to GAAP Information | Three Months Ended | ||||||||||||||
June 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 | $ | 171,637 | $ | 14,426 | $ | 157,211 | |||||||||
Gain (loss) on derivative instruments | (65,872 | ) | $ | - | (65,872 | ) | |||||||||
Total Revenues | 105,765 | 14,426 | 91,339 | ||||||||||||
Operating Costs and Expenses | |||||||||||||||
Oil, natural gas liquids and natural gas production | 42,840 | 5,660 | 37,180 | ||||||||||||
Production and ad valorem taxes | 11,265 | 1,236 | 10,029 | ||||||||||||
O&G Depreciation, depletion and amortization | 115,768 | 6,368 | 109,400 | ||||||||||||
FF&E Depreciation, depletion and amortization | 1,267 | 71 | 1,196 | ||||||||||||
Asset impairment | - | - | - | ||||||||||||
Exploration | 1,520 | 32 | 1,488 | ||||||||||||
General and administrative † | 23,548 | 10 | 23,538 | ||||||||||||
Accretion of discount on asset retirement obligations | 1,779 | 248 | 1,531 | ||||||||||||
(Gain) loss on sale of assets and other | (161,097 | ) | (160,944 | ) | (153 | ) | |||||||||
Total costs and expenses | 36,890 | (147,319 | ) | 184,209 | |||||||||||
Operating Income (Loss) | 68,875 | 161,745 | (92,870 | ) | |||||||||||
Other Income/(Expense) | |||||||||||||||
Interest expense | (9,038 | ) | - | (9,038 | ) | ||||||||||
Other income | 63 | (1 | ) | 64 | |||||||||||
Total other expense |
(8,975 | ) | (1 | ) | (8,974 | ) | |||||||||
Income (Loss) Before Income Taxes | 59,900 | 161,744 | (101,844 | ) | |||||||||||
Income tax expense (benefit) | 23,141 | 58,204 | (35,063 | ) | |||||||||||
Net Income (Loss) | $ | 36,759 | $ | 103,540 | $ | (66,781 | ) | ||||||||
Diluted Earnings Per Average Common Share | $ | 0.38 | $ | 1.06 | $ | (0.69 | ) | ||||||||
Basic earning Per Average Common Share | $ | 0.38 | $ | 1.06 | $ | (0.69 | ) | ||||||||
Oil | 3,558 | 238 | 3,320 | ||||||||||||
NGL | 1,067 | 212 | 855 | ||||||||||||
Natural Gas | 1,216 | 292 | 924 | ||||||||||||
Total Production (mboe) | 5,841 | 742 | 5,099 | ||||||||||||
Total Production (boepd) | 64,187 | 8,154 | 56,033 | ||||||||||||
Note: Amounts may not sum due to rounding | |||||||||||||||
† General and administrative includes $866 of expense related to the reductions in force | |||||||||||||||
CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED) For the 3 months ending June 30, 2017 and 2016 |
|||||||||||||||
2nd Quarter | |||||||||||||||
(in thousands, except per share data) | 2017 | 2016 | Change | ||||||||||||
Revenues | |||||||||||||||
Oil, natural gas liquids and natural gas sales | $ | 218,723 | $ | 171,637 | $ | 47,086 | |||||||||
Gain (loss) on derivative instruments, net | 38,101 | (65,872 | ) | 103,973 | |||||||||||
Total revenues | 256,824 | 105,765 | 151,059 | ||||||||||||
Operating Costs and Expenses | |||||||||||||||
Oil, natural gas liquids and natural gas production | 43,909 | 42,840 | 1,069 | ||||||||||||
Production and ad valorem taxes | 13,218 | 11,265 | 1,953 | ||||||||||||
Depreciation, depletion and amortization | 121,549 | 117,035 | 4,514 | ||||||||||||
Asset impairment | 29 | − | 29 | ||||||||||||
Exploration | 1,998 | 1,520 | 478 | ||||||||||||
General and administrative (including stock based compensation of $3,191 and $5,504 for the three months ended June 30, 2017, and 2016, respectively) |
|
19,792 |
|
23,548 |
|
(3,756 |
) |
||||||||
Accretion of discount on asset retirement obligations | 1,443 | 1,779 | (336 | ) | |||||||||||
(Gain) loss on sale of assets and other | 172 | (161,097 | ) | 161,269 | |||||||||||
Total operating costs and expenses | 202,110 | 36,890 | 165,220 | ||||||||||||
Operating Income | 54,714 | 68,875 | (14,161 | ) | |||||||||||
Other Income (Expense) | |||||||||||||||
Interest expense | (9,145 | ) | (9,038 | ) | (107 | ) | |||||||||
Other income | 45 | 63 | (18 | ) | |||||||||||
Total other expense | (9,100 | ) | (8,975 | ) | (125 | ) | |||||||||
Income Before Income Taxes | 45,614 | 59,900 | (14,286 | ) | |||||||||||
Income tax expense | 16,133 | 23,141 | (7,008 | ) | |||||||||||
Net Income | $ | 29,481 | $ | 36,759 | $ | (7,278 | ) | ||||||||
Diluted Earnings Per Average Common Share | $ | 0.30 | $ | 0.38 | $ | (0.08 | ) | ||||||||
Basic Earnings Per Average Common Share | $ | 0.30 | $ | 0.38 | $ | (0.08 | ) | ||||||||
Diluted Average Common Shares Outstanding | 97,693 | 97,389 | 304 | ||||||||||||
Basic Average Common Shares Outstanding | 97,189 | 97,067 | 122 | ||||||||||||
CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED) For the 6 months ending June 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 | $ | 395,098 | $ | 294,401 | $ | 100,697 | |||||||||
Gain (loss) on derivative instruments, net | 102,647 | (60,417 | ) | 163,064 | |||||||||||
Total revenues | 497,745 | 233,984 | 263,761 | ||||||||||||
Operating Costs and Expenses | |||||||||||||||
Oil, natural gas liquids and natural gas production | 85,197 | 90,567 | (5,370 | ) | |||||||||||
Production and ad valorem taxes | 26,038 | 22,435 | 3,603 | ||||||||||||
Depreciation, depletion and amortization | 221,201 | 236,397 | (15,196 | ) | |||||||||||
Asset impairment | 1,489 | 220,025 | (218,536 | ) | |||||||||||
Exploration | 5,634 | 1,762 | 3,872 | ||||||||||||
General and administrative (including stock based compensation of $6,388 and $7,975 for the six months ended June 30, 2017, and 2016, respectively) |
40,191 |
53,073 |
(12,882 |
) |
|||||||||||
Accretion of discount on asset retirement obligations | 2,857 | 3,536 | (679 | ) | |||||||||||
Gain on sale of assets and other | (1,003 | ) | (160,875 | ) | 159,872 | ||||||||||
Total operating costs and expenses | 381,604 | 466,920 | (85,316 | ) | |||||||||||
Operating Income (Loss) | 116,141 | (232,936 | ) | 349,077 | |||||||||||
Other Income (Expense) | |||||||||||||||
Interest expense | (18,111 | ) | (18,871 | ) | 760 | ||||||||||
Other income | 428 | 159 | 269 | ||||||||||||
Total other expense | (17,683 | ) | (18,712 | ) | 1,029 | ||||||||||
Income (Loss) Before Income Taxes | 98,458 | (251,648 | ) | 350,106 | |||||||||||
Income tax expense (benefit) | 35,574 | (85,291 | ) | 120,865 | |||||||||||
Net Income (Loss) | $ | 62,884 | $ | (166,357 | ) | $ | 229,241 | ||||||||
Diluted Earnings Per Average Common Share | $ | 0.64 | $ | (1.81 | ) | $ | 2.45 | ||||||||
Basic Earnings Per Average Common Share | $ | 0.65 | $ | (1.81 | ) | $ | 2.46 | ||||||||
Diluted Average Common Shares Outstanding | 97,648 | 91,850 | 5,798 | ||||||||||||
Basic Average Common Shares Outstanding | 97,165 | 91,850 | 5,315 | ||||||||||||
CONSOLIDATED BALANCE SHEETS (UNAUDITED) As of June 30, 2017 and December 31, 2016 |
||||||||
|
||||||||
(in thousands) | June 30, 2017 | December 31, 2016 | ||||||
ASSETS | ||||||||
Current Assets | ||||||||
Cash and cash equivalents | $ | 498 | $ | 386,093 | ||||
Accounts receivable, net | 104,359 | 73,322 | ||||||
Inventories, net | 18,263 | 14,222 | ||||||
Derivative instruments | 39,063 | 50 | ||||||
Income tax receivable | 301 | 27,153 | ||||||
Prepayments and other | 4,410 | 5,071 | ||||||
Total current assets | 166,894 | 505,911 | ||||||
Property, Plant and Equipment | ||||||||
Oil and natural gas properties, net | 4,513,743 | 4,016,683 | ||||||
Other property and equipment, net | 45,241 | 44,869 | ||||||
Total property, plant and equipment, net | 4,558,984 | 4,061,552 | ||||||
Other postretirement assets | 3,595 | 3,619 | ||||||
Noncurrent derivative instruments | 9,534 | − | ||||||
Other assets | 7,725 | 8,741 | ||||||
TOTAL ASSETS | $ | 4,746,732 | $ | 4,579,823 | ||||
LIABILITIES AND SHAREHOLDERS’ EQUITY |
||||||||
Current Liabilities | ||||||||
Long-term debt due within one year | 17,000 | 24,000 | ||||||
Accounts payable | 65,770 | 65,031 | ||||||
Accrued taxes | 12,734 | 7,252 | ||||||
Accrued wages and benefits | 15,709 | 25,089 | ||||||
Accrued capital costs | 95,509 | 79,988 | ||||||
Revenue and royalty payable | 48,332 | 51,217 | ||||||
Derivative instruments | 481 | 65,467 | ||||||
Other | 17,778 | 20,160 | ||||||
Total current liabilities | 273,313 | 338,204 | ||||||
Long-term debt | 659,158 | 527,443 | ||||||
Asset retirement obligations | 84,867 | 81,544 | ||||||
Deferred income taxes | 532,605 | 495,888 | ||||||
Noncurrent derivative instruments | 502 | 3,006 | ||||||
Other long-term liabilities | 8,545 | 13,136 | ||||||
Total liabilities | 1,558,990 | 1,459,221 | ||||||
Total Shareholders’ Equity | 3,187,742 | 3,120,602 | ||||||
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | $ | 4,746,732 | $ | 4,579,823 | ||||
SELECTED BUSINESS SEGMENT DATA (UNAUDITED) For the 3 months ending June 30, 2017 and 2016 |
|||||||||||||||
2nd 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 | $ | 182,701 | $ | 146,360 | $ | 36,341 | |||||||||
Natural gas liquids | 18,634 | 13,928 | 4,706 | ||||||||||||
Natural gas | 17,388 | 11,349 | 6,039 | ||||||||||||
Total | $ | 218,723 | $ | 171,637 | $ | 47,086 | |||||||||
Open non-cash mark-to-market gains (losses) on derivative instruments | |||||||||||||||
Oil | $ | 31,067 | $ | (54,729 | ) | $ | 85,796 | ||||||||
Natural gas liquids | 4,530 | − | 4,530 | ||||||||||||
Natural gas | 1,737 | (5,896 | ) | 7,633 | |||||||||||
Total | $ | 37,334 | $ | (60,625 | ) | $ | 97,959 | ||||||||
Closed gains (losses) on derivative instruments | |||||||||||||||
Oil | $ | 152 | $ | (6,297 | ) | $ | 6,449 | ||||||||
Natural gas liquids | (80 | ) | − | (80 | ) | ||||||||||
Natural gas | 695 | 1,050 | (355 | ) | |||||||||||
Total | $ | 767 | $ | (5,247 | ) | $ | 6,014 | ||||||||
Total revenues | $ | 256,824 | $ | 105,765 | $ | 151,059 | |||||||||
Production volumes | |||||||||||||||
Oil (MBbl) | 4,102 | 3,558 | 544 | ||||||||||||
Natural gas liquids (MMgal) | 51.6 | 44.8 | 6.8 | ||||||||||||
Natural gas (MMcf) | 7,596 | 7,296 | 300 | ||||||||||||
Total production volumes (MBOE) |
6,596 |
5,841 | 755 | ||||||||||||
Average daily production volumes |
|||||||||||||||
Oil (MBbl/d) |
45.1 |
39.1 |
6.0 |
||||||||||||
Natural gas liquids (MMgal/d) | 0.6 | 0.5 | 0.1 | ||||||||||||
Natural gas (MMcf/d) | 83.5 | 80.2 | 3.3 | ||||||||||||
Total average daily production volumes (MBOE/d) | 72.5 | 64.2 | 8.3 | ||||||||||||
Average realized prices excluding effects of open non-cash mark-to-market derivative instruments | |||||||||||||||
Oil (per barrel) | $ | 44.58 | $ | 39.37 | $ | 5.21 | |||||||||
Natural gas liquids (per gallon) | $ | 0.36 | $ | 0.31 | $ | 0.05 | |||||||||
Natural gas (per Mcf) | $ | 2.38 | $ | 1.70 | $ | 0.68 | |||||||||
Average realized prices excluding effects of all derivative instruments | |||||||||||||||
Oil (per barrel) | $ | 44.54 | $ | 41.14 | $ | 3.40 | |||||||||
Natural gas liquids (per gallon) | $ | 0.36 | $ | 0.31 | $ | 0.05 | |||||||||
Natural gas (per Mcf) | $ | 2.29 | $ | 1.56 | $ | 0.73 | |||||||||
Costs per BOE | |||||||||||||||
Oil, natural gas liquids and natural gas production expenses |
$ |
6.66 |
$ |
7.34 |
$ |
(0.68 |
) |
||||||||
Production and ad valorem taxes | $ | 2.00 | $ | 1.93 | $ | 0.07 | |||||||||
Depreciation, depletion and amortization | $ | 18.43 | $ | 20.04 | $ | (1.61 | ) | ||||||||
Exploration expense | $ | 0.30 | $ | 0.26 | $ | 0.04 | |||||||||
General and administrative | $ | 3.00 | $ | 4.03 | $ | (1.03 | ) | ||||||||
Capital expenditures (including acquisitions) | $ | 336,111 | $ | 92,962 | $ | 243,149 | |||||||||
SELECTED BUSINESS SEGMENT DATA (UNAUDITED) For the 6 months ending June 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 | $ | 329,371 | $ | 248,517 | $ | 80,854 | |||||||||
Natural gas liquids | 34,268 | 22,517 | 11,751 | ||||||||||||
Natural gas | 31,459 | 23,367 | 8,092 | ||||||||||||
Total | $ | 395,098 | $ | 294,401 | $ | 100,697 | |||||||||
Open non-cash mark-to-market gains (losses) on derivative instruments | |||||||||||||||
Oil | $ | 89,125 | $ | (56,428 | ) | $ | 145,553 | ||||||||
Natural gas liquids | 11,617 | − | 11,617 | ||||||||||||
Natural gas | 8,961 | (4,454 | ) | 13,415 | |||||||||||
Total | $ | 109,703 | $ | (60,882 | ) | $ | 170,585 | ||||||||
Closed gains (losses) on derivative instruments | |||||||||||||||
Oil | $ | (5,858 | ) | $ | (1,203 | ) | $ | (4,655 | ) | ||||||
Natural gas liquids | (1,545 | ) | − | (1,545 | ) | ||||||||||
Natural gas | 347 | 1,668 | (1,321 | ) | |||||||||||
Total | $ | (7,056 | ) | $ | 465 | $ | (7,521 | ) | |||||||
Total revenues | $ | 497,745 | $ | 233,984 | $ | 263,761 | |||||||||
Production volumes | |||||||||||||||
Oil (MBbl) | 7,098 | 6,944 | 154 | ||||||||||||
Natural gas liquids (MMgal) | 85.3 | 84.8 | 0.5 | ||||||||||||
Natural gas (MMcf) | 13,326 | 14,742 | (1,416 | ) | |||||||||||
Total production volumes (MBOE) |
11,350 |
11,421 | (71 | ) | |||||||||||
Average daily production volumes |
|||||||||||||||
Oil (MBbl/d) |
39.2 |
38.2 |
1.0 |
||||||||||||
Natural gas liquids (MMgal/d) | 0.5 | 0.5 | − | ||||||||||||
Natural gas (MMcf/d) | 73.6 | 81.0 | (7.4 | ) | |||||||||||
Total average daily production volumes (MBOE/d) | 62.7 | 62.8 | (0.1 | ) | |||||||||||
Average realized prices excluding effects of open non-cash mark-to-market derivative instruments | |||||||||||||||
Oil (per barrel) | $ | 45.58 | $ | 35.62 | $ | 9.96 | |||||||||
Natural gas liquids (per gallon) | $ | 0.38 | $ | 0.27 | $ | 0.11 | |||||||||
Natural gas (per Mcf) | $ | 2.39 | $ | 1.70 | $ | 0.69 | |||||||||
Average realized prices excluding effects of all derivative instruments | |||||||||||||||
Oil (per barrel) | $ | 46.40 | $ | 35.79 | $ | 10.61 | |||||||||
Natural gas liquids (per gallon) | $ | 0.40 | $ | 0.27 | $ | 0.13 | |||||||||
Natural gas (per Mcf) | $ | 2.36 | $ | 1.59 | $ | 0.77 | |||||||||
Costs per BOE | |||||||||||||||
Oil, natural gas liquids and natural gas production expenses |
$ |
7.51 |
$ |
7.93 |
$ |
(0.42 |
) |
||||||||
Production and ad valorem taxes | $ | 2.29 | $ | 1.96 | $ | 0.33 | |||||||||
Depreciation, depletion and amortization | $ | 19.49 | $ | 20.70 | $ | (1.21 | ) | ||||||||
Exploration expense | $ | 0.50 | $ | 0.15 | $ | 0.35 | |||||||||
General and administrative | $ | 3.54 | $ | 4.65 | $ | (1.11 | ) | ||||||||
Capital expenditures (includes acquisitions) | $ | 720,246 | $ | 217,050 | $ | 503,196 | |||||||||
View source version on businesswire.com: http://www.businesswire.com/news/home/20170808005486/en/