OKLAHOMA CITY--(BUSINESS WIRE)--Chesapeake Energy Corporation (NYSE:CHK) today announced details of its 2014 Outlook and capital program.
- Expected total capital expenditures to range from $5.2 – $5.6 billion
- Projected production growth of 8 – 10%, adjusted for asset sales
- Estimated per-unit production and G&A expenses to decline 10% and 25%, respectively, year over year
- Targeted long-term production growth per debt-adjusted share of 5 – 9% annually
Doug Lawler, Chesapeake’s Chief Executive Officer, said, "2013 was a transformational year for the company and its stakeholders. The Chesapeake team worked diligently on several major initiatives designed to ensure that our processes and practices maximize returns from our exceptional asset base. We have established specific strategic goals and metrics that we believe will drive us toward top-quartile operational, financial and shareholder return performance among our peers. Disciplined capital allocation, budget and cost leadership programs are now in place, and I am very excited about Chesapeake’s opportunity to become a differential investment and industry partner of choice in 2014 and beyond."
Capital Program and Production Outlook
Chesapeake is budgeting total capital expenditures in the range of $5.2 – $5.6 billion in 2014, which represents a 20% reduction from the midpoint of Chesapeake’s 2013 capital expenditure Outlook range. After adjusting for 2013 asset sales, the company expects to generate 8 – 10% year-over-year production growth in 2014, consisting of 8 – 12% oil production growth, 44 – 49% natural gas liquids production growth and 4 – 6% natural gas production growth. On an absolute basis, Chesapeake is targeting 2014 production growth of 2 – 4%, which implies an average daily production rate of 680 – 695 thousand barrels of oil equivalent (mboe).
Chesapeake plans to spud approximately 1,100 gross operated wells in 2014, which is relatively unchanged from 2013 activity levels. The company plans to connect approximately 1,300 gross operated wells to sales in 2014, or approximately 115 fewer wells than in 2013. Lawler commented, "Our improving capital efficiency has made it possible for us to forecast similar adjusted production growth in 2014 compared to 2013, despite a substantial reduction in capital expenditures and approximately 8% fewer operated wells expected to be connected to sales."
Cost Overview
As a result of ongoing cost control initiatives, Chesapeake anticipates lower per-unit production and general and administrative (G&A) expenses in 2014. Production expenses are expected to range from $4.25 – $4.75 per barrel of oil equivalent (boe), down approximately 10% year over year from the midpoint of Chesapeake’s 2013 production expense Outlook range. G&A expenses (excluding restructuring and other termination benefits) are estimated to be $1.35 – $1.60 per boe, down approximately 25% year over year from the midpoint of Chesapeake’s 2013 G&A expense Outlook range.
Lawler concluded, "We are encouraged by the progress we have made during the second half of 2013, and I look forward to our efforts yielding strong financial results in 2014. While our guidance today does not reflect the impact of potential divestitures, we continue to pursue opportunities to high-grade our portfolio through asset sales. We believe these transactions will be value accretive and enable us to further reduce financial complexity and improve overall leverage. Over the last eight months, we have conducted an extensive review of Chesapeake’s portfolio. Due to the size and quality of the asset base, I am confident that by remaining focused on our strategic priorities we can deliver long-term production growth per debt-adjusted share of 5 – 9% annually, while maintaining a disciplined capital spending profile."
A complete summary of the company’s guidance for 2014 is provided in the Outlook dated February 6, 2014, which is attached to this release as Schedule "A" beginning on Page 4.
Key Play Information
The following table details December 2013 average production rates, year-end drilled well inventory, estimated 2014 exploration and production (E&P) capital expenditures and 2014 estimated operated rig count by play:
| Dec '13 Avg. | 12/31/2013 | 2014E | 2014E | |||||
| Daily Net | Drilled Well | % of | Avg. | |||||
| Production | Inventory | Total E&P | Operated | |||||
| Play | (mboe/d) | (Gross Op'd) | Capex(1) | Rig Count | ||||
| Eagle Ford | 90 | 109 | ~35% | 15 - 18 | ||||
| Mid-Continent(2) | 100 | 32 | ~20% | 15 - 17 | ||||
| Utica | 35 | 195 | ~15% | 7 - 9 | ||||
| Marcellus North | 141 | 112 | ~10% | 6 - 7 | ||||
| Haynesville | 90 | 11 | ~10% | 7 - 9 | ||||
| PRB Niobrara | 7 | 46 | ~5% | 3 | ||||
| Marcellus South | 52 | 47 | <5% | 1 | ||||
| Barnett | 74 | 58 | <5% | 1 | ||||
| Other | 60 | - | - | - | ||||
| Total | 649 | 610 | 55-65 | |||||
| (1) Net of Utica and PRB drilling carries; includes drilling, completion, leasehold, geological and geophysical costs and capitalized G&A excludes capitalized interest | ||||||||
| (2) Includes: Mississippian Lime, Cleveland, Tonkawa, Colony and Texas Panhandle Granite Washes and other Anadarko plays | ||||||||
2014 Analyst Day
Chesapeake will host its 2014 Analyst Day on Friday, May 16, 2014 at its headquarters in Oklahoma City. The meeting will be webcast live on Chesapeake's website for those who are unable to attend.
2014 Outlook and Capital Program Conference Call Information
A conference call to discuss this release has been scheduled for Thursday, February 6, 2014, at 9:00 am EST. The telephone number to access the conference call is 913-312-1521 or toll-free 888-264-8893. The passcode for the call is 7669165. We encourage those who would like to participate in the call to place calls between 8:50 and 9:00 am EST. For those unable to participate in the conference call, a replay will be available for audio playback at 2:00 pm EST on Thursday, February 6, 2014, and will run through 2:00 pm EST on Thursday, February 20, 2014. The number to access the conference call replay is 719-457-0820 or toll-free 888-203-1112. The passcode for the replay is 7669165. The conference call will also be webcast live on Chesapeake’s website at www.chk.com in the "Events” subsection of the "Investors” section of the company’s website. The webcast of the conference will be available on the company’s website for one year.
Chesapeake Energy Corporation (NYSE:CHK) is the second-largest producer of natural gas and the 11th largest producer of oil and natural gas liquids in the U.S. Headquartered in Oklahoma City, the company's operations are focused on discovering and developing its large and geographically diverse resource base of unconventional natural gas and oil assets onshore in the U.S. The company also owns substantial marketing, compression and oilfield services businesses. Further information is available at www.chk.com where Chesapeake routinely posts announcements, updates, events, investor information, presentations and news releases.
This news release and the accompanying Outlook include "forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are statements other than statements of historical fact that give our current expectations or forecasts of future events. They include production forecasts, estimates of operating costs, planned development drilling, expected capital expenditures, expected efficiency gains, projected operating cash flow, business strategy and other plans and objectives for future operations. Although we believe the expectations and forecasts reflected in the forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties.
Factors that could cause actual results to differ materially from expected results are described under "Risk Factors” in Item 1A of our 2012 annual report on Form 10-K filed with the U.S. Securities and Exchange Commission on March 1, 2013. These risk factors include the volatility of natural gas, oil and NGL prices; the limitations our level of indebtedness may have on our financial flexibility; declines in the prices of natural gas and oil potentially resulting in a write-down of our asset carrying values; the availability of capital on an economic basis to fund reserve replacement costs; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of natural gas, oil and NGL reserves and projecting future rates of production and the amount and timing of development expenditures; our ability to generate profits or achieve targeted results in drilling and well operations; leasehold terms expiring before production can be established; hedging activities resulting in lower prices realized on natural gas, oil and NGL sales; the need to secure hedging liabilities and the inability of hedging counterparties to satisfy their obligations; drilling and operating risks, including potential environmental liabilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing, air emissions and endangered species; oilfield services shortages, gathering system and transportation capacity constraints and various transportation interruptions that could adversely affect our revenues and cash flow; losses possible from pending or future litigation and regulatory investigations; and cyber attacks adversely impacting our operations. In addition, disclosures concerning the estimated contribution of derivative contracts to our future results of operations are based upon market information as of a specific date. These market prices are subject to significant volatility. Our production forecasts are also dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity. We caution you not to place undue reliance on our forward-looking statements, which speak only as of the date of this news release, and we undertake no obligation to update this information, except as required by applicable law.
SCHEDULE "A”
MANAGEMENT’S OUTLOOK AS OF FEBRUARY 6, 2014
Chesapeake periodically provides management guidance on certain factors that affect the company’s future financial performance. Please note that the company has changed its oil and natural gas unit equivalent reporting convention to oil equivalent. Combined oil, natural gas and NGL volume amounts are shown below in boe rather than mcfe.
|
Chesapeake Energy Corporation Consolidated Projections |
||
|
Year Ending |
||
| Absolute Production Growth:(a) | ||
| Liquids | 14 – 18% | |
| Oil | 1 – 5% | |
| NGL(b) | 40 – 45% | |
| Natural gas | (2) – 0% | |
| Total production | 2 – 4% | |
| Daily Equivalent Rate – mboe | 680 – 695 | |
| NYMEX Price(c) (for calculation of realized hedging effects only): | ||
| Oil - $/bbl | $90.40 | |
| Natural gas - $/mcf | $4.16 | |
| Estimated Realized Hedging Effects(d) (based on assumed NYMEX prices above): | ||
| Oil - $/bbl | ($2.80) | |
| Natural gas - $/mcf | ($0.07) | |
| Estimated Gathering/Marketing/Transportation/Basis Differentials to NYMEX Prices: | ||
| Oil - $/bbl | $2.80 – 4.80 | |
| NGL - $/bbl | $63.00 – 67.00 | |
| Natural gas - $/mcf | $1.60 – 1.70 | |
| Operating Costs per Boe of Projected Production: | ||
| Production expense | $4.25 – 4.75 | |
| Production taxes | $0.85 – 0.95 | |
| General and administrative(e) | $1.20 – 1.40 | |
| Stock-based compensation (noncash) | $0.15 – 0.20 | |
| DD&A of natural gas and liquids assets | $10.50 – 11.50 | |
| Depreciation of other assets | $1.20 – 1.30 | |
| Interest expense(f) | $0.95 – 1.05 | |
| Other ($ millions): | ||
| Marketing, gathering and compression net margin(g) | $50 – 70 | |
| Oilfield services net margin(g) | $175 – 225 | |
| Net income attributable to noncontrolling interests and other(h) | ($160 – 190) | |
| Book Tax Rate | 38% | |
| Weighted Average Shares Outstanding (in millions): | ||
| Basic | 657 – 661 | |
| Diluted | 767 – 771 | |
| Operating Cash Flow before Changes in Assets and Liabilities ($ in millions)(i) (j) | $5,100 – 5,300 | |
| Total Capital Expenditures ($ in millions) | $5,200 – 5,600 | |
a) Growth ranges based on the midpoint of company Outlook issued on 11/6/13.
b) Assumes ethane recovery in the Utica and Southern Marcellus to fulfill Chesapeake’s pipeline commitments, no ethane recovery in the Rockies, minimal ethane recovery in the Eagle Ford and partial ethane recovery in the Mid-Continent.
c) NYMEX natural gas and oil prices have been updated for actual contract prices through February and January, respectively.
d) Includes expected settlements for commodity derivatives adjusted for option premiums. For derivatives closed early, settlements are reflected in the period of original contract expiration.
e) Excludes expenses associated with stock-based compensation and restructuring and other termination benefits.
f) Does not include gains (losses) on interest rate derivatives for settlement periods beyond 2014.
g) Includes revenue and operating costs and excludes depreciation and amortization of other assets.
h) Net income attributable to noncontrolling interests of Chesapeake Granite Wash Trust, CHK Utica, LLC and CHK Cleveland Tonkawa, LLC.
i) A non-GAAP financial measure. We are unable to provide reconciliation to projected cash provided by operating activities, the most comparable GAAP measure, because of uncertainties associated with projecting future changes in assets and liabilities.
j) Assumes NYMEX prices on open contracts of $4.00 per mcf and $90.00 per bbl and production growth rate ranges as shown above.
Natural Gas, Oil and NGL Hedging Activities
Chesapeake enters into natural gas, oil and NGL derivative transactions in order to mitigate a portion of its exposure to adverse changes in market prices. Please see the quarterly reports on Form 10-Q and annual reports on Form 10-K filed by Chesapeake with the SEC for detailed information about derivative instruments the company uses, its quarter-end and year-end derivative positions and accounting for natural gas, oil and NGL derivatives.
The company’s natural gas hedging positions as of January 31, 2014 were as follows:
|
Open Natural Gas Swaps; Gains (Losses) from Closed Natural Gas Trades and Call Option Premiums |
|||||||||||
|
Open
Swaps (bcf) |
Avg. NYMEX
Price of Open Swaps |
Total Gains (Losses) from Closed Trades and Premiums for Call Options ($ in millions) |
|||||||||
| Q1 2014 | 169 | $ | 4.36 | $ | (26 | ) | |||||
| Q2 2014 | 106 | 4.08 | (12 | ) | |||||||
| Q3 2014 | 111 | 4.08 | (15 | ) | |||||||
| Q4 2014 | 111 | 4.08 | (21 | ) | |||||||
| Total 2014 | 497 | $ | 4.18 | $ | (74 | ) | |||||
| Total 2015 | 44 | $ | 4.53 | $ | (131 | ) | |||||
| Total 2016 – 2022 | 0 | $ | — | $ | (187 | ) | |||||
|
Natural Gas Three-Way Collars |
||||||||||||||
|
Open
Collars (bcf) |
Avg. NYMEX
Sold Put Price |
Avg. NYMEX
Bought Put Price |
Avg. NYMEX
Ceiling Price |
|||||||||||
| Q1 2014 | 48 | $ | 3.57 | $ | 4.08 | $ | 4.39 | |||||||
| Q2 2014 | 51 | 3.57 | 4.09 | 4.38 | ||||||||||
| Q3 2014 | 57 | 3.55 | 4.09 | 4.38 | ||||||||||
| Q4 2014 | 71 | 3.49 | 4.11 | 4.37 | ||||||||||
| Total 2014 | 227 | $ | 3.54 | $ | 4.09 | $ | 4.38 | |||||||
| Total 2015 | 174 | $ | 3.38 | $ | 4.21 | $ | 4.41 | |||||||
|
Natural Gas Swaptions |
||||||
|
Swaptions
(bcf) |
Avg. NYMEX
Strike Price |
|||||
| Q1 2014 | 0 | $ | — | |||
| Q2 2014 | 12 | 4.80 | ||||
| Q3 2014 | 0 | — | ||||
| Q4 2014 | 0 | — | ||||
| Total 2014 | 12 | $ | 4.80 | |||
|
Natural Gas Written Call Options |
||||||
|
Call Options
(bcf) |
Avg. NYMEX
Strike Price |
|||||
| Total 2016 – 2020 | 193 | $ | 9.92 | |||
|
Natural Gas Basis Protection Swaps |
|||||||
|
Volume
(bcf) |
Avg. NYMEX plus/(minus) | ||||||
| Q1 2014 | 8 | $ | 1.68 | ||||
| Q2 2014 | 20 | (0.49 | ) | ||||
| Q3 2014 | 20 | (0.50 | ) | ||||
| Q4 2014 | 12 | (0.44 | ) | ||||
| Total 2014 | 60 | $ | (0.19 | ) | |||
| Total 2015 | 31 | $ | (0.34 | ) | |||
| Total 2016 - 2022 | 8 | $ | (1.02 | ) | |||
The company’s crude oil hedging positions as of January 31, 2014 were as follows:
|
Open Crude Oil Swaps; Gains (Losses) from Closed Crude Oil Trades and Call Option Premiums |
|||||||||||
|
Open
Swaps (mbbls) |
Avg. NYMEX
Price of Open Swaps |
Total Gains (Losses) from
Closed Trades and Premiums for Call Options ($ in millions) |
|||||||||
| Q1 2014 | 7,217 | $ | 94.37 | $ | (44 | ) | |||||
| Q2 2014 | 7,114 | 93.97 | (46 | ) | |||||||
| Q3 2014 | 5,137 | 93.57 | (48 | ) | |||||||
| Q4 2014 | 5,112 | 93.58 | (49 | ) | |||||||
| Total 2014 | 24,580 | $ | 93.92 | $ | (187 | ) | |||||
| Total 2015 | 693 | $ | 89.48 | $ | 252 | ||||||
| Total 2016 – 2022 | 0 | $ | — | $ | 117 | ||||||
|
Crude Oil Written Call Options |
||||||
|
Call Options
(mbbls) |
Avg. NYMEX
Strike Price |
|||||
| Q1 2014 | 612 | $ | 83.53 | |||
| Q2 2014 | 619 | 83.53 | ||||
| Q3 2014 | 626 | 83.53 | ||||
| Q4 2014 | 626 | 83.53 | ||||
| Total 2014 | 2,483 | $ | 83.53 | |||
| Total 2015 | 15,823 | $ | 93.12 | |||
| Total 2016 – 2017 | 24,220 | $ | 100.07 | |||
|
Crude Oil Basis Protection Swaps |
||||
| Volume (mbbls) | Avg. NYMEX plus | |||
| Q1 2014 | 90 | $ | 6.00 | |
| Q2 2014 | 91 | $ | 6.00 | |
| Q3 2014 | 92 | $ | 6.00 | |
| Q4 2014 | 92 | $ | 6.00 | |
| Total 2014 | 365 | $ | 6.00 | |
